Integrated downhole system with plural telemetry subsystems

ABSTRACT

A downhole system has a plurality of telemetry systems and a control system configured to obtain information from one or more sensors and transmit that information on one or more of the plurality of telemetry systems. The configuration of a controller may be changed so as to change which information is transmitted on a given telemetry system and how the information is to be transmitted on the given telemetry system.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a divisional of U.S. application Ser. No. 15/433,626filed on 15 Feb. 2017, which is a continuation of U.S. application Ser.No. 14/770,336 filed on 25 Aug. 2015 and now issued as U.S. Pat. No.9,605,535, which is a 371 of PCT Application No. PCT/CA2014/050133 filed25 Feb. 2014. PCT Application No. PCT/CA2014/050133 claims priority fromU.S. Application No. 61/768,936 filed 25 Feb. 2013 and entitled DOWNHOLETELEMETRY and U.S. Application No. 61/769,033 filed 25 Feb. 2013 andentitled DOWNHOLE ELECTROMAGNETIC AND MUD PULSE TELEMETRY APPARATUS,both of which are hereby incorporated herein by reference for allpurposes as if fully set forth herein.

TECHNICAL FIELD

This application relates to subsurface drilling, specifically todownhole data acquisition and telemetry between downhole assemblies andsurface equipment. Embodiments are applicable to drilling wells forrecovering hydrocarbons.

BACKGROUND

Recovering hydrocarbons from subterranean zones typically involvesdrilling wellbores.

Wellbores are made using surface-located drilling equipment which drivesa drill string that eventually extends from the surface equipment to theformation or subterranean zone of interest. The drill string can extendthousands of feet or meters below the surface. The terminal end of thedrill string includes a drill bit for drilling (or extending) thewellbore. Drilling fluid, usually in the form of a drilling “mud”, istypically pumped through the drill string. The drilling fluid cools andlubricates the drill bit and also carries cuttings back to the surface.Drilling fluid may also be used to help control bottom hole pressure toinhibit hydrocarbon influx from the formation into the wellbore andpotential blow out at surface.

Bottom hole assembly (BHA) is the name given to the equipment at theterminal end of a drill string. In addition to a drill bit, a BHA maycomprise elements such as: apparatus for steering the direction of thedrilling (e.g. a steerable downhole mud motor or rotary steerablesystem); sensors for measuring properties of the surrounding geologicalformations (e.g. sensors for use in well logging); sensors for measuringdownhole conditions as drilling progresses; one or more systems fortelemetry of data to the surface; stabilizers; heavy weight drillcollars; pulsers; and the like. The BHA is typically advanced into thewellbore by a string of metallic tubulars (drill pipe).

Modern drilling systems may include any of a wide range ofmechanical/electronic systems in the BHA or at other downhole locations.Such electronics systems may be packaged as part of a downhole probe. Adownhole probe may comprise any active mechanical, electronic, and/orelectromechanical system that operates downhole. A probe may provide anyof a wide range of functions including, without limitation: dataacquisition; measuring properties of the surrounding geologicalformations (e.g. well logging); measuring downhole conditions asdrilling progresses; controlling downhole equipment; monitoring statusof downhole equipment; directional drilling applications; measuringwhile drilling (MWD) applications; logging while drilling (LWD)applications; measuring properties of downhole fluids; and the like. Aprobe may comprise one or more systems for: telemetry of data to thesurface; collecting data by way of sensors (e.g. sensors for use in welllogging) that may include one or more of vibration sensors,magnetometers, inclinometers, accelerometers, nuclear particledetectors, electromagnetic detectors, acoustic detectors, and others;acquiring images; measuring fluid flow; determining directions; emittingsignals, particles or fields for detection by other devices; interfacingto other downhole equipment; sampling downhole fluids; etc. A downholeprobe is typically suspended in a bore of a drill string near the drillbit.

A downhole probe may communicate a wide range of information to thesurface by telemetry. Telemetry information can be invaluable forefficient drilling operations. For example, telemetry information may beused by a drill rig crew to make decisions about controlling andsteering the drill bit to optimize the drilling speed and trajectorybased on numerous factors, including legal boundaries, locations ofexisting wells, formation properties, hydrocarbon size and location,etc.

In directional drilling operations the drill bit is steered to cause thewellbore to follow a curved trajectory. In some cases the drill bit isrotated by a mud motor located in the BHA. A portion of drill stringabove the drill bit may have a bend in it which can be oriented to pushor deflect the drill bit in a desired direction.

In order to control drilling so that the wellbore follows a desiredtrajectory it is valuable if not essential to have information about thecurrent orientation of the drill bit. A crew may make intentionaldeviations from the planned path as necessary based on informationgathered from downhole sensors and transmitted to the surface bytelemetry during the drilling process. This information may betransmitted and acted upon in real time or near real-time. The abilityto obtain and transmit reliable data from downhole locations allows forrelatively more economical and more efficient drilling operations.

There are several known telemetry techniques. These include transmittinginformation by generating vibrations in fluid in the bore hole (e.g.acoustic telemetry or mud pulse (MP) telemetry) and transmittinginformation by way of electromagnetic signals that propagate at least inpart through the earth (EM telemetry). Other example telemetrytechniques use hardwired drill pipe, fibre optic cable, or drill collaracoustic telemetry to carry data to the surface.

MP telemetry involves creating pressure waves in the circulating drillmud in the drill string. In MP telemetry, information may be transmittedby creating a series of pressure waves in the mud column. This may beachieved by changing the flow area and/or path of the drilling fluid asit passes a downhole probe in a timed, coded sequence, thereby creatingpressure differentials in the drilling fluid. The pressure differentialsor pulses may either be negative pulses and/or positive pulses orcontinuous wave. The pulses travel to surface where they may be detectedby transducers in the surface piping. The detected pulses can then bedecoded to reconstruct the data sent from the downhole probe. One ormore signal processing techniques may be used to separate undesired mudpump noise, rig noise or downward propagating noise from upward (MWD)signals. The best data transmission rate achievable by current MPtelemetry is about 40 bit/s. However, the achievable data rate falls offwith increasing depth. It is not uncommon for MP data rates from deeperlocations to be on the order of 1 to 2 bit/s.

A typical arrangement for EM telemetry uses parts of the drill string asan antenna. The drill string may be divided into two conductive sectionsby including an insulating joint or connector (a “gap sub”) in the drillstring. The gap sub is typically placed at the top of a bottom holeassembly such that metallic drill pipe in the drill string above the BHAserves as one antenna element and metallic sections in the BHA serve asanother antenna element. Electromagnetic telemetry signals can then betransmitted by applying electrical signals between the two antennaelements. The signals typically comprise very low frequency AC signalsapplied in a manner that codes information for transmission to thesurface (higher frequency signals are typically attenuated more stronglythan low frequency signals). The electromagnetic signals may be detectedat the surface, for example by measuring electrical potentialdifferences between the drill string or a metal casing that extends intothe ground and one or more ground electrodes.

Advantages of EM telemetry relative to MP telemetry include generallyfaster data rates, increased reliability due to no moving downholeparts, high resistance to lost circulating material (LCM) use, andsuitability for air/underbalanced drilling. An EM system can transmitdata without a continuous fluid column; hence it is useful when there isno drilling fluid flowing. This is advantageous when a drill crew isadding a new section of drill pipe as the EM signal can transmitinformation (e.g. directional information) while the drill crew isadding the new pipe. Disadvantages of EM telemetry include lower depthcapability, incompatibility with some formations (for example, high saltformations and formations of high resistivity contrast). Also, as the EMtransmission is strongly attenuated over long distances through theearth formations, it may require a relatively large amount of power forthe signals to be detected at surface. The electrical power available togenerate EM signals may be provided by batteries or another power sourcethat has limited capacity.

Drill rig operators sometimes provide in a drill string multipleindependently-operating telemetry systems, each coupled with sensorsystems such that each telemetry system communicates to a surfacereceiver readings collected by the sensor systems with which it iscoupled. This requires substantial duplication of parts and additionalbatteries in the BHA, resulting in increased length of the BHA,increased cost, and (insofar as the sensors are necessarily positionedfurther away from the drill bit in the elongated BHA) decreasedrelevance of sensor readings. Furthermore, such known multiple telemetrysystems are not optimized for performance, reliability, and efficientuse of power.

One challenge facing designers of downhole telemetry systems is toachieve acceptably high data rates. Especially when attempting telemetryfrom locations that are deep in a wellbore, data rates can be so slowthat transmitting even relatively small amounts of data can take longtimes, e.g. several minutes. This interferes with the goal ofmaintaining real time control over the drilling operation and creates abottleneck which can slow the progress of drilling. It would be of greatbenefit to the industry to provide ways to achieve higher rates oftransmission of telemetry data.

Another challenge facing the industry is improving the reliability oftelemetry equipment. This problem is exacerbated because the downholeenvironment is typically harsh—being characterized by high pressures,high flow rates of potentially erosive drilling mud, high temperaturesand/or extreme vibration. These conditions stress equipment, especiallyelectronic equipment. It would be of great benefit to the industry toprovide fault-tolerant/fault-resistant telemetry systems.

Another challenge facing the industry is to extend the run-time ofdownhole equipment. Many downhole electronic systems arebattery-powered. Batteries tend to be more reliable than downhole powergenerators. However, batteries have limited capacity. Tripping equipmentout of a wellbore to replace batteries is time-consuming and expensive.Methods and apparatus which can allow battery-powered downholeelectronic systems to function for longer times between replacingbatteries would be of great value.

There remains a need for downhole telemetry systems and methods thatameliorate at least some of the disadvantages of existing telemetrysystems.

SUMMARY

The invention has a number of aspects. One main aspect relates to anarchitecture for downhole systems that facilitates the use of aplurality of telemetry systems. The architecture may be implemented in away that provides great flexibility in configuring the systems totransmit data of various kinds to surface equipment. In some embodimentslogically separate controllers are associated with each of a pluralityof telemetry subsystems. Each controller may be configured toindependently obtain sensor information (or other telemetry data) and totransmit the sensor information by way of the associated telemetrysubsystem. Another main aspect relates to different ways in which adownhole system may be configured to transmit data and different methodsthat may be executed by downhole systems for configuring the downholesystems and/or transmitting data to surface equipment. There is synergybetween these main aspects in that the described architecture isparticularly advantageous for configuring in the manners described andfor practicing the described methods. However, these main aspects of theinvention are also capable of separate application. Another aspect ofthe invention relates to methods and apparatus for receiving anddecoding downhole telemetry data. In some embodiments the methods andapparatus integrate a plurality of telemetry receivers.

In some embodiments a downhole system is flexibly reconfigurable amongmultiple configurations without changing the physical structure of thedownhole system. The reconfiguration may be accomplished by executingsoftware instructions and/or by replacing electronically-readableconfiguration profiles for example.

One aspect provides telemetry systems that comprise a plurality oftelemetry controllers each associated with a corresponding telemetrysubsystem. The telemetry controllers may be configured to independentlyobtain and transmit parameter values, such as sensor readings using theassociated telemetry subsystem.

Another aspect provides telemetry methods. Some such methods compriseautomatically switching among different telemetry configurations basedon one or more factors as described herein. Some such methods maycomprise one or more of:

-   -   conditionally transmitting certain data (e.g. certain parameter        values).    -   detecting a status of drilling operations at a downhole tool and        switching among telemetry configurations based on the detected        status.    -   transmitting at least some of the same data by way of two or        more different telemetry subsystems.    -   automatically inhibiting operation of one or more telemetry        systems based on a configuration setting.

Another example aspect provides downhole systems comprising a pluralityof telemetry subsystems and a control system comprising a plurality oftelemetry controllers. Each of the plurality of telemetry controllers isassociated and in communication with at least one telemetry subsystem ofthe plurality of telemetry subsystems. The system includes a data bus.Each of the plurality of telemetry controllers is in communication witheach other telemetry controller of the plurality of telemetrycontrollers via the bus. The system includes one or more sensors incommunication with the plurality of telemetry controllers. A firsttelemetry controller of the plurality of telemetry controllers isassociated with a first telemetry subsystem of the plurality oftelemetry subsystems and is operable to obtain first sensor informationfrom a first set of the one or more sensors and to transmit the firstsensor information on the first telemetry subsystem. A second telemetrycontroller of the plurality of telemetry controllers is associated witha second telemetry subsystem of the plurality of telemetry subsystemsand is operable independently of the first telemetry controller toobtain second sensor information from a second set of the one or moresensors and to transmit the second sensor information on the secondtelemetry subsystem.

In some embodiments the first telemetry subsystem is an EM telemetrysubsystem and the second telemetry subsystem is an MP telemetrysubsystem. In some embodiments, all of the sensors are accessible by allof the plurality of telemetry controllers via the data bus such that anyof the data controllers can obtain readings from any of the sensors. Insome embodiments the sensors include a plurality of sensors of the sametype such that one or more backup sensors are available in case onesensor fails.

Another example aspect provides methods comprising, from a downholetool, transmitting values for one or more parameters using a telemetryprotocol. The methods include storing the transmitted parameter valuesat the downhole tool and acquiring new values for the one or moreparameters. The methods compare the new parameter values to the storedpreviously-transmitted parameter values and in at least some casessuppress transmitting the new parameter values if a difference betweenthe new parameter values and the stored previously-transmitted parametervalues is less than a threshold.

Another example aspect provides methods for transmitting data from adownhole location, the methods comprise obtaining a data unit to betransmitted to surface equipment; transmitting a first part of the dataunit using a first telemetry subsystem and transmitting a second part ofthe data unit using a second telemetry subsystem. An advantage of somesuch methods is reduced latency.

Another example aspect provides methods for downhole telemetry, themethods comprise, at a downhole system obtaining a sensor valueexpressed as a plurality of digital bits by reading a sensor anddividing the plurality of bits into first and second sets of bits. Themethods transmit the first set of bits using a first telemetry systemand transmit the second set of bits using a second telemetry system. Insome embodiments the first and second telemetry systems are of differenttypes (e.g. an MP telemetry system or an acoustic telemetry system andan EM telemetry system).

Another example aspect provides methods for transmitting downholemeasurement data to surface equipment. The methods comprise (a) readingdownhole measurement data; (b) selecting an available telemetrytransmission mode from a group consisting of: mud pulse (MP)—onlytelemetry mode, electromagnetic (EM)—only telemetry mode, MP and EMconcurrent shared telemetry mode, and MP and EM concurrent confirmationtelemetry mode; (c) when the MP-only telemetry mode is selected,encoding the measurement data into a first MP telemetry signal andtransmitting the first MP telemetry signal to surface; (d) when theEM-only mode is selected, encoding the measurement data into a first EMtelemetry signal and transmitting the first EM telemetry signal tosurface; (e) when the concurrent shared telemetry mode is selected,encoding a first selection of the measurement data into a second MPtelemetry signal and a second selection of the measurement data into asecond EM telemetry signal, and transmitting the second MP and EMtelemetry signals to surface; and (f) when the concurrent confirmationtelemetry mode is selected, encoding the same measurement data into athird MP telemetry signal and into a third EM telemetry signal; andtransmitting the third MP and EM telemetry signals to surface.

Another example aspect provides downhole telemetry methods. The methodscomprise: (a) at a downhole location, reading measurement data andencoding some of the measurement data into an electromagnetic (EM)telemetry signal and the rest of the measurement data into a mud pulse(MP) telemetry signal, then (b) transmitting the EM and MP telemetrysignals to surface wherein at least part of the EM and MP telemetrysignals are transmitted concurrently.

Another example aspect provides downhole telemetry methods. The methodscomprise (a) at a downhole location, reading measurement data andencoding the same measurement data into an electromagnetic (EM)telemetry signal and into a mud pulse (MP) telemetry signal, thentransmitting the EM and MP telemetry signals to surface, wherein atleast part of the EM and MP telemetry signals are transmittedconcurrently; and (b) at surface, receiving the EM and MP telemetrysignals, comparing the received signals and determining whether thesignals meet a match threshold.

Another example aspect provides drilling methods comprising advancing adrill string while pumping drilling fluid through a bore of the drillstring during active drilling periods separated by flow-off periodsduring which the flow of drilling fluid through the drill string isdiscontinued. The methods involve communicating telemetry data from adownhole system comprising an EM telemetry subsystem and an MP telemetrysubsystem to surface equipment. The methods comprise establishing achanged MP data communication protocol for transmitting data using theMP telemetry subsystem, the changed MP data communication protocol to beeffective upon commencement of an active drilling period after aflow-off period, and, during the flow-off period, transmitting headerinformation for the changed data MP communication protocol from thedownhole system to the surface equipment using the EM telemetrysubsystem.

Another example aspect provides drilling methods comprising advancing adrill string while pumping drilling fluid through a bore of the drillstring during active drilling periods separated by flow-off periodsduring which the flow of drilling fluid through the drill string isdiscontinued and communicating telemetry data from a downhole system tosurface equipment. The methods comprise establishing a datacommunication protocol having slots for a plurality of specific dataitems and, at the downhole system, determining whether or not totransmit a specific one of the plurality of data items based on acomparison of a current value of the specific one of the plurality ofdata items with one or more previously-transmitted values for thespecific one of the plurality of data items.

Another example aspect provides drilling methods comprising advancing adrill string while pumping drilling fluid through a bore of the drillstring during active drilling periods separated by flow-off periodsduring which the flow of drilling fluid through the drill string isdiscontinued; and communicating telemetry data from a downhole system tosurface equipment using one or both of EM telemetry and MP telemetry.The methods comprise, at the downhole system, detecting the beginning ofone of the flow-off periods, assembling a header specifying a way inwhich data will be transmitted by EM and/or MP telemetry; andtransmitting the header to the surface equipment using EM telemetry at apredetermined time after the beginning of the flow-off period.

Another example aspect provides drilling methods comprising advancing adrill string while pumping drilling fluid through a bore of the drillstring during active drilling periods separated by flow-off periodsduring which the flow of drilling fluid through the drill string isdiscontinued; and communicating telemetry data from a downhole system tosurface equipment using one or both of EM telemetry and MP telemetry.The methods comprise, at the downhole system, transmitting telemetrydata by EM telemetry; monitoring an electrical output current of an EMtelemetry transmitter; and, if the electrical output current meets orexceeds a predetermined threshold, automatically switching to transmitthe telemetry data by MP telemetry.

Another example aspect provides downhole telemetry tools comprising:sensors for acquiring downhole measurement data; an electromagnetic (EM)telemetry unit; a mud pulse (MP) telemetry unit; at least one controlmodule communicative with the sensors and EM and MP telemetry units andcomprising a processor and a memory having encoded thereon program codeexecutable by the processor to perform a method as described herein.

Another example aspect provides surface equipment for processingdownhole telemetry signals. The surface equipment comprises an MPtelemetry signal detector; an EM telemetry signal detector; a display;and a control system configured to: receive a first set of bits via theMP telemetry signal detector; receive a second set of bits via the EMtelemetry signal detector; combine the first and second sets of bits toyield a data unit; and optionally display the data unit on the display.

Another aspect comprises a downhole tool comprising a pressure-tighthousing and two or more telemetry drivers for different telemetry modes(for example EM and MP) contained within the pressure-tight housing.

Another aspect provides a receiver for telemetry information configuredto track and display information identifying readings that have changedsince data values were most recently updated.

Another aspect provides a telemetry system comprising: a plurality oftelemetry subsystems and a control system comprising a plurality oftelemetry controllers. Each telemetry controller is associated and incommunication with at least one telemetry subsystem of the plurality oftelemetry subsystems. Each telemetry controller of the plurality oftelemetry controllers is in communication with each other telemetrycontroller of the plurality of telemetry controllers via a bus. One ormore sensors is in communication with the plurality of telemetrycontrollers. A first telemetry controller of the plurality of telemetrycontrollers is configured to obtain first sensor information from afirst set of the one or more sensors and to transmit the first sensorinformation on a first telemetry subsystem of the plurality of telemetrysubsystems. A second telemetry controller of the plurality of telemetrycontrollers is configured to obtain second sensor information from asecond set of the one or more sensors and to transmit the second sensorinformation on a second telemetry subsystem of the plurality oftelemetry subsystems. The telemetry controllers may be configured toindependently control whether or not the associated telemetry subsystemis operative to transmit data and/or to independently control what datais transmitted by the associated telemetry subsystem.

In example embodiments the telemetry subsystems comprise an EM telemetrysubsystem and an MP telemetry subsystem.

Another aspect provides a method of configuring a telemetry system. Themethod comprises receiving first information and in response toreceiving the first information, configuring a first telemetrycontroller to transmit a first sensor information on a first telemetrysubsystem. The method further comprises receiving second information,and in response to receiving the second information, reconfiguring thefirst telemetry controller to transmit a second sensor information onthe first telemetry subsystem. The work mode may be controlled bydownlink information.

Another aspect provides a method of operating a telemetry system. Themethod comprises receiving, at a first controller, first sensorinformation from a first set of sensors, transmitting by a firsttelemetry subsystem, the first sensor information, receiving, at asecond controller, second sensor information from a second set ofsensors, and transmitting by a second telemetry subsystem, the secondsensor information.

Another aspect provides a telemetry system comprising: one or moresensors; a first telemetry subsystem in communication with the one ormore sensors; a second telemetry subsystem in communication with the oneor more sensors; and a control system configured to obtain first sensorinformation from a first set of the one or more sensors and to transmitthe first sensor information on a first telemetry subsystem and toobtain second sensor information from a second set of the one or moresensors and to transmit the second sensor information on a secondtelemetry subsystem.

Another aspect provides apparatus comprising any new useful andinventive feature, combination of features or sub-combination offeatures described or clearly inferred herein.

Another aspect provides a method comprising any new, useful andinventive step, act, combination of steps and/or acts, orsub-combination of steps and/or acts described or clearly inferredherein.

Further aspects of the invention and features of example embodiments areillustrated in the accompanying drawings and/or described in thefollowing description.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings illustrate non-limiting example embodiments ofthe invention.

FIG. 1 is a schematic view of an example drilling operation.

FIG. 2 is a logical diagram of an example telemetry system.

FIG. 2A is a logical diagram of another example telemetry system.

FIG. 3 is a schematic view of an example embodiment of a telemetrysystem according to FIG. 2.

FIG. 3A is a block diagram illustrating an example embodiment of atelemetry system that includes a power control subsystem.

FIG. 4 is a schematic view of an example EM signal generator.

FIG. 5 is a cross-sectional view of an example MP signal generator.

FIG. 6 is a schematic view of an example telemetry configuration system.

FIG. 6A is a schematic view of an alternative telemetry configurationsystem.

FIG. 7 is a flowchart diagram of an example method for updating atelemetry configuration system according to FIG. 6.

FIG. 8 is a block diagram of a plurality of controllers of a downholetelemetry apparatus and the operations that they may carry out inresponse to a downlink command.

FIGS. 9 to 12 are respectively flow charts illustrating methods that maybe performed by a telemetry apparatus while operating in: MP onlytelemetry mode, EM only telemetry mode, concurrent confirmationtelemetry mode, and concurrent shared telemetry mode.

FIGS. 11A and 12A are graphs of mud flow, drill string rotation speed,EM telemetry transmission, and MP telemetry transmission as a functionof time when a telemetry tool is operating in concurrent confirmationtelemetry mode and concurrent shared telemetry mode, respectively.

FIG. 13 is a schematic block diagram showing surface components of anexample telemetry system.

FIG. 14 is a logic diagram applied by an example telemetry system todetermine the confidence values of received EM and MP telemetry signalsthat were transmitted by a telemetry apparatus operating in concurrentconfirmation mode.

DESCRIPTION

Throughout the following description specific details are set forth inorder to provide a more thorough understanding to persons skilled in theart. However, well known elements may not have been shown or describedin detail to avoid unnecessarily obscuring the disclosure. The followingdescription of examples of the technology is not intended to beexhaustive or to limit the system to the precise forms of any exampleembodiment. Accordingly, the description and drawings are to be regardedin an illustrative, rather than a restrictive, sense.

Example Drilling Situation

FIG. 1 shows schematically an example drilling operation. A drill rig 10drives a drill string 12 which includes sections of drill pipe thatextend to a drill bit 14. The illustrated drill rig 10 includes aderrick 10A, a rig floor 10B and draw works 10C for supporting the drillstring. Drill bit 14 is larger in diameter than the drill string abovethe drill bit. An annular region 15 surrounding the drill string istypically filled with drilling fluid. The drilling fluid is pumped by amud pump 15A through an electrically isolating gap sub assembly 13, abore in the drill string to the drill bit and returns to the surfacethrough annular region 15 carrying cuttings from the drilling operation.As the well is drilled, a casing 16 may be made in the well bore. Thecasing may be surrounded by concrete. A blow out preventer 17 issupported at a top end of the casing. The drill rig illustrated in FIG.1 is an example only. The methods and apparatus described herein are notspecific to any particular type of drill rig.

The gap sub assembly 13 contains an electrically isolated(nonconductive) portion, creating an electrically insulating break,known as a gap, between the top and bottom parts of the gap sub assembly13. The gap sub assembly 13 may form part of the BHA and be positionedat the top part of the BHA. Conducting portions above and below the gapsub assembly 13 may form the antennae of a dipole antenna. The dipoleantenna may be used for EM telemetry.

Further, a system like that of FIG. 1 may include a system forcommunicating information between the surface and a downhole location.Thus it is possible to provide two-way communication between the surfaceand a downhole tool. The principles described herein may be applied toone-way data communication or two-way data communication or even tomulti-way data communication between a plurality of downhole devices andthe surface.

In the illustrated embodiment, a downhole system 20 is in datacommunication with surface equipment which includes a surfacetransceiver 26. Downhole system 20 may use two or more telemetrytechniques to communicate data to surface transceiver 26. In someembodiments these telemetry techniques are distinct telemetry techniques(telemetry techniques that apply different physical principles forcommunicating data). For example, the telemetry techniques may beselected from: electromagnetic telemetry, mud pulse telemetry, drillstring acoustic telemetry, mud acoustic telemetry, etc.

Downhole system 20 may comprise two or more hardware components whichmay be mounted at two or more separate locations (e.g. a mud pulsegenerator mounted to the drill string at a first location and an EMsignal generator mounted to the drill string at a second location).

In an example embodiment that also has certain advantages the twotelemetry techniques include electromagnetic telemetry and mud pulsetelemetry. In mud pulse telemetry, data is communicated through the useof mud pulses 22, which are generated at a downhole location, receivedby a pulse transducer 24 and communicated to surface transceiver 26.Pulse transducer 24 may, for example, comprise a pressure sensor thatdetects variations in the pressure of the drilling fluid in drill string12.

Electromagnetic telemetry comprises generating electromagnetic waves ata downhole location. The electromagnetic waves 28 propagate to thesurface. FIG. 1 shows equipotential lines 28A and lines of current flow28B representing an electromagnetic wave 28. These lines are schematicin nature as the earth is typically non-uniform. The electromagneticwaves 28 may be detected by surface transceiver 26. In the illustratedembodiment, surface transceiver 26 is connected to measure potentialdifferences between one or more ground electrodes 30 and drill string12.

Surface transceiver 26 may be coupled to pulse transducer 24, electrodes30, and drill string 12 (the connection to drill string 12 may, forexample, be by way of blow out preventer 17) by communication cables 27.

Surface transceiver 26 may comprise or be in communication with acomputer 32. Computer 32 may comprise a data store for saving loggeddata. Computer 32 may also comprise a display by which receivedinformation may be displayed to one or more users.

Surface transceiver 26 may optionally be configured to transmitinformation to downhole system 20 using any one or more telemetrytechniques for which surface transceiver 26 is equipped to transmit.This facility may enable users of drill rig 10 to send, for example,control information to downhole system 20 and, therefore, to the bottomhole assembly. Surface transceiver 26 may, in some embodiments, transmitdata to downhole system 20 using one or more telemetry techniques forwhich downhole system 20 is equipped to receive (and not necessarilytransmit) data. For example, in a drill rig 10 in which the drill stringis driven from the surface, data may be transmitted to downhole system20 by varying drilling parameters (such as speed and/or direction ofrotation of the drill string). Surface transceiver 26 may also, oralternatively, transmit data to downhole system 20 using one or moretelemetry techniques for which downhole system 20 is equipped to bothreceive and transmit data. For example, a downhole system 20 withelectromagnetic telemetry capabilities may be configured to both receiveand transmit data using electromagnetic telemetry.

Downhole System Architectures

Downhole systems according to some embodiments of the invention providetwo or more separate telemetry systems that may be applied in waysdescribed herein to transmit data to surface equipment from downhole.FIGS. 2 and 2A show two examples of such downhole systems.

FIG. 2 shows logically an example downhole system 40. A control system42 is in communication with one or more sensor systems 44 and one ormore telemetry systems 46. Sensor system 44 may comprise a plurality ofsensors. The sensors may be any sensors known in the art or laterdeveloped and could include, for example, one or more of: shock sensors,RPM sensors, flow sensors, direction and inclination sensors,accelerometers, magnetometers, gamma logging sensors, pressure sensors,resistivity sensors, temperature sensors, fluid property sensors,neutron sensors, and the like.

In the depicted example, telemetry systems 46 comprise one or more EMtelemetry systems 46A and one or more MP telemetry systems 46B. Controlsystem 42 receives sensor data from sensor system(s) 44 and provides allor part of the received data to one or more of the telemetry systems 46for transmission.

Control System and Controllers

Control system 42 may comprise one physical device or a plurality ofdevices configured to work independently or collectively to receiveand/or transmit data using telemetry systems 46. In some embodiments,such as the example embodiment depicted in FIGS. 2A and 3, eachtelemetry system 46 is associated with a corresponding controller. Anadditional number of controllers may be provided, each in associationwith one or more sensors of sensor system 44. All of these controllersmay collectively make up control system 42.

A controller (e.g. control system 42 or separate controllers 42A and 42Bor any other controller, control system or control module describedherein) may comprise any suitable device or combination of devices. Insome embodiments each controller comprises one or more programmabledevices such as one or more devices selected from: CPUs, dataprocessors, embedded processors, digital signal processors,microprocessors, computers-on-a-chip, or the like. The processor(s) maycomprise, for example, embedded processors such as dsPIC33 series MPUs(multi-core processing units) available from Microchip Technology Inc.of Chandler, Ariz., USA. These programmable devices are configured byway of software and/or firmware to perform the required controllerfunctions and are interfaced to other parts of the downhole system byway of suitable interfaces. In some embodiments two or more controllersmay be implemented in software running on the same processor or set ofprocessors. In addition or in the alternative to the use of programmabledevices a controller may comprise logic circuits, which may behard-wired, provided in custom IC chips, or the like and/or configurablelogic such as field-programmable gate arrays (FPGAs).

Each controller may comprise one or more corresponding data stores. Adata store may be separate or shared among two or more controllers. Thedata stores may comprise any suitable devices for storing data and/orsoftware instructions. For example, the data stores may comprise memorychips, memory cards, read only memory (ROM), non-volatile memory, randomaccess memory (RAM), solid-state memory, optical memory, magnetic memoryor the like. The data store(s) may contain program code executable bythe programmable device(s) to encode sensor measurements into telemetrydata and to send control signals to telemetry units (e.g. an EM or MPtelemetry unit) to transmit telemetry signals to the surface.

Housings

The components of downhole systems as described herein may be at leastpartially contained in a housing (see e.g. element 51 in FIG. 3). Forexample, controller elements of a downhole system may be containedwithin housing 51. The housing may be constructed as a pressure-tighthousing sealed to prevent ingress of fluids into the housing atpressures in the downhole environment.

Some or all of the sensor elements of the downhole system may optionallybe located outside of housing 51. The elements contained within ahousing 51 may be implemented on one or more circuit boards, connectedby suitable electrical and logical wiring, and/or interconnected in anyother suitable manner known in the art. The circuit board(s) may beprinted circuit boards with one or more controllers soldered to thesurface of the board(s). The circuit board(s) may be secured on acarrier device (not shown) which is fixed inside housing 51, for exampleby end cap structures (not shown).

In one embodiment, housing 51 comprises a single pressure-tight housing.It is advantageous to provide a compact telemetry apparatus thatcomprises drivers for two or more telemetry methods within a singlepressure-tight housing. Some embodiments feature a probe housing 51 thatis both shorter and wider than current industry standards. In acurrently preferred embodiment, the probe housing is substantiallyshorter than current industry-standard telemetry probes, measuring lessthan 6 feet (about 2 meters), and preferably no more than 4 feet (about1.3 meters) in length.

In some embodiments housing 51 comprises a cylindrical tube made up oftwo metallic parts with an electrically-insulating break between them.EM signals from a generator inside housing 51 may be connected to themetallic parts of the housing which may, in turn, be in electricalcontact with the two sides of a gap sub. In some embodiments, housing 51is positioned such that housing 51 spans the gap of the gap sub withportions of housing 51 extending to either side of gap sub 78.

It can be beneficial to configure apparatus 50 such that theelectrically-insulating break in housing 51 is located away fromsensitive electronics of apparatus 50. For example, theelectrically-insulating break may be located near one end of housing 51.The electrically-insulating break can be anywhere along housing 51 inother embodiments. All that is required is a structure that permits twooutputs of a signal generator to be connected to opposing sides of a gapsub.

Downhole systems as described herein are not limited to being housed inprobes within a bore of a drill string. For example, all or part of adownhole system may be housed in a pocket within a wall of a drillstring component.

FIG. 2A shows another example telemetry system 40A in which controlsystem 42 comprises a dedicated controller for each telemetry system 46.FIG. 2A shows a controller 42A for EM telemetry system 46A and acontroller 42B for MP telemetry system 46B. If additional telemetrysystems are provided then additional controllers may be provided. Thearrangement of FIG. 2A has particular advantages as discussed herein.

FIG. 3 shows schematically a downhole system 50 according to an exampleembodiment. Downhole system 50 is a more specific example of the generalarchitecture exemplified by downhole system 40A.

Example telemetry apparatus 50 comprises a plurality of controllerswhich together make up control system 42. The illustrated embodimentincludes status sensor controller 52, interface sensor controller 60, EMcontroller 70, MP controller 80, and power controller 90. Components ofapparatus 50 are housed in a housing 51

Status sensor controller 52 is connected to sensors which monitorparameters relevant to the current status of the drill string. In someembodiments, outputs of one or more such sensors is used to controlswitching one or more systems of apparatus 50 on or off, to switchapparatus 50 among a number of operating modes or to otherwise controlthe operation of such systems. In the depicted embodiment, such sensorsinclude flow switch sensor 54, which detects the status of the drillingfluid flow switch in the BHA, RPM gyro sensor 56, which detects rotationspeed of the BHA and gyroscopic information, and shock sensor 58, whichmay detect shock forces encountered by the BHA in three-dimensions.

Status sensor controller 52 may, for example use readings from theassociated sensors to distinguish between different drilling modes. Forexample, status sensor controller 52 may be configured to distinguishbetween a ‘quiet’ wellbore (no drilling fluid flow and no drill stringrotation), ‘sliding’ operation (drilling fluid is flowing but the drillstring is not being rotated significantly from the surface), and full-ondrilling (drilling fluid is flowing and the drill string is beingrotated from the surface). In some embodiments operation of apparatus 50is automatically configured differently depending on the currentdrilling mode (as detected, for example, by status sensor controller52).

Interface sensor controller 60 is generally in communication withsensors that monitor parameters that are indicative of characteristicsof the surrounding formation and/or the position of the BHA relative tothe formation. Such sensors may include, for example, direction andinclination sensor 62, gamma sensor 64, which measures the compositionof the surrounding formation through the measurement of gamma emission,and direction and inclination backup sensor 66. Additional sensors ofany suitable types may be provided.

In the illustrated embodiment, apparatus 50 has a set of backup sensors67. Interface sensor controller 60 may connect to backup sensors 67and/or a backup interface sensor controller 60A may connect to backupsensors 67. Backup sensors 67 may replicate some or all sensors inapparatus 50 to provide redundancy in case of failure of a main sensor.Readings from backup sensors may be used in various ways as describedbelow.

Example EM Telemetry Hardware

EM controller 70 is in communication with an EM telemetry sub-system. Insome embodiments the generator for EM signals comprises a power supplyhaving first and second outputs and an H-bridge circuit connected to theoutputs such that the power supply outputs can be connected to opposingsides of gap sub 78 (for example, by way of electrically separatedconductive parts of housing 51) in either polarity. The power supplymay, for example, comprise a current-limited DC power supply whichapplies power from a battery to the H-bridge circuit.

For example, in a first configuration of the H-bridge, one power supplyoutput is electrically connected to an uphole side of gap sub 78 and theother power supply output is connected to the downhole side of gap sub78. In a second H-bridge configuration the power supply outputs arereversed such that the first power supply output is electricallyconnected to the downhole side of gap sub 78 and the second power supplyoutput is electrically connected to the uphole side of gap sub 78. Thefirst and second power supply outputs are at different potentials (e.g.ground and a set voltage relative to ground or a set voltage positivewith respect to a local ground reference and another set voltagenegative with respect to a local ground reference).

An alternating signal of a desired frequency may be applied across gapsub 78 by switching the H-bridge between the first and secondconfigurations described above at twice the desired frequency. AnH-bridge driver 76 that includes the H-bridge circuit may be located ator near the electrically-insulating break in housing 51. Thisfacilitates a relatively direct connection of H-bridge driver 76 to thesides of gap sub 78.

FIG. 4 shows a more detailed view of a possible arrangement for an EMtelemetry transmitter. EM telemetry unit 75 comprises EM controller 70,signal generator 72, EM amplifier 74, battery 96, and H-bridge driver76. An H-bridge circuit enables a voltage to be applied across a load ineither direction, and comprises four switches of which one pair ofswitches can be closed and the other pair of switches left open to allowvoltage to be applied between two outputs in one direction (“positivepolarity pathway”), and another pair of switches can be closed while thefirst pair of switches is left open to allow a voltage to be appliedbetween the two outputs in a reverse direction (“reverse polaritypathway”). In H-bridge driver 76, switches S1, S2, S3, and S4 arearranged so that switches S1 and S4 are electrically coupled to one sideof the gap sub 78 and switches S2 and S3 are electrically coupled to theother side of the gap sub 78. Switches S1 and S3 can be closed toestablish the positive polarity pathway such that a voltage appliedacross gap sub 78 generates a positive EM wave and switches S2 and S4can be closed to establish the reverse polarity pathway such that thevoltage applied across the gap of gap sub 78 generates a negative EMwave.

EM signal generator 72 is configured to receive a telemetry signal fromEM controller 70 and to translate the telemetry signal into analternating current control signal which is then sent to EM amplifier74. Amplifier 74 is configured to amplify the control signal receivedfrom EM signal generator 72 using power from battery 96 and to then sendthe amplified control signal to H-bridge driver 76 which applies theamplified control signal across the gap of the gap sub with a polaritydetermined by the settings of the switches in the H-bridge circuit togenerate EM telemetry signals.

In an example embodiment, EM signal generator 72 comprises a digital toanalog converter (DAC) which is controlled to output a waveform thatencodes data to be transmitted. The waveform may comprise a sine wavefor example and the data may be encoded in the phase and/or frequency ofthe waveform. The waveform is amplified by amplifier 74. The gain ofamplifier 74 may be set, for example by a configuration file, to adjustthe amplitude of transmitted EM telemetry signals to a level that iscapable of being received by surface transceiver 26. H-bridge driver 76,applies an alternating voltage across gap sub 78 on the exterior ofhousing 51. The polarity of the H-bridge circuit may be controlledaccording to the phase of the waveform output by amplifier 74.

The apparatus in FIG. 4 is just one of many possible ways of generatingEM telemetry signals. Other ways of generating EM telemetry signals maybe used with the invention described herein.

EM controller 70 may communicate any information accessible to it tousers of a drill rig 10 by providing digital signals encoding suchinformation to EM signal generator 72. For example, EM controller 70 maycommunicate information measured by one or more sensors and provided toEM controller 70 by the associated sensor controller, such as statussensor controller 52 or interface sensor controller 60.

EM controller 70 may use one or more modulation techniques to encodetelemetry data into a telemetry signal comprising EM carrier waves. Forexample, EM controller 70 may use amplitude shift keying (ASK),frequency shift keying (FSK), phase shift keying (PSK), quadrature phaseshift keying (QPSK) or combinations thereof such as amplitude and phaseshift keying (APSK).

Example MP Telemetry Hardware

MP controller 80 controls the mud pulse telemetry sub-system byproviding signals to a motor driver 82 which then operates motor 84.Motor 84 may then open and/or close valve 86 so as to increase ordecrease pressure in the drill string 12 or otherwise induce acousticpulses or oscillations in the drilling fluid in a pattern that encodesdata. MP controller 80 may receive information from the surface bydetecting the flow of drilling fluid in drill string 12. For example, adrilling operator may control the flow of drilling fluid in a patternthat conveys information to apparatus 50. This may be implemented, insome embodiments, by communicating the sensor readings of flow switchsensor 54 through status sensor controller 52 to MP controller 80.Alternatively, or in addition, MP controller 80 may be configured tohave direct or indirect access to flow switch sensor 54, pressure sensor94, or other sensor(s) configured to detect messages received fromsurface transceiver 26 or actions of a drilling operator without the useof intervening status sensor controller 52.

MP controller 80 may use one or more modulation techniques to encodetelemetry data into a telemetry signal comprising mud pulses. Forexample, MP controller 80 may use amplitude shift keying (ASK), timingshift keying (TSK), or combinations thereof such as amplitude and timingshift keying (ATSK). The keying may optionally be binary keying as in,for example, binary phase shift keying (BPSK) or binary amplitude shiftkeying (BASK) or binary frequency shift keying (BFSK). The keying mayoptionally transmit symbols each representing a plurality of bits, forexample, using 4 PSK or 8 PSK keying.

ASK involves assigning each symbol of a defined symbol set to a uniquepattern of pulse amplitudes. TSK involves assigning each symbol of adefined symbol set to a unique timing position or combination of timingpositions in a time period.

FIG. 5 shows an example arrangement of an MP telemetry transmitter. MPtelemetry unit 85A may be used in place of the simple combination ofmotor 84 and valve 86, as shown in FIG. 3. MP telemetry unit 85Acomprises a rotor and stator assembly 150 and a pulser assembly 152 bothof which are axially located inside a drill collar 155 with an annulargap therebetween to allow mud to flow through the gap. The rotor andstator assembly 150 comprises a stator 153 and a rotor 154. Stator 153is fixed relative to drill collar 155 and rotor 154 is fixed to a driveshaft 156 of the pulser assembly 152. Pulser assembly 152 is also fixedrelative to drill collar 155, although this is not shown in FIG. 5. Thepulser assembly 152 also includes an electrical motor 157 which ispowered by battery 96 (not shown in FIG. 5) and which is coupled to thedrive shaft 156 as well as to associated circuitry 158 which in turn iscommunicative with the MP controller 80 (not shown in FIG. 5). The motorcircuitry 158 receives the encoded telemetry signal from the MPcontroller 80 and generates a motor control signal which causes motor157 to rotate rotor 154 relative to stator 153 (via driveshaft 156) in acontrolled pattern to generate pressure pulses in the drilling fluidflowing through rotor 154.

The apparatus illustrated in FIG. 5 is just one of many possible ways ofgenerating MP telemetry signals. Other ways of generating MP telemetrysignals may be used in the systems described herein.

Power Management

Power controller 90 is in electrical communication with one or morepower sources such as one or more batteries 96 and generally manages theprovision of electrical power to all or some of telemetry apparatus 50.In some embodiments, power controller 90 may selectively provide powerto any one or more of the controllers and/or their associatedsub-systems and/or reduce or cut off power to certain of the controllersand/or sub-systems when possible to save power. In some embodiments,power controller 90 may cause certain controllers to switch into alow-power mode. For example, the power controller may cause one or moreother controllers to operate at reduced clock rates to save electricalpower. Power controller 90 may be provided with a capacitor bank 92 forthe short- or long-term storage of energy.

In some embodiments power controller 90 is operable to turn ON or turnOFF the entire downhole system (with the possible exception of powercontroller 90 which may remain powered to enable turning the downholesystem back ON in selected circumstances). Controller 90 may also beoperable to selectively enable or disable individual telemetry units(e.g. an EM telemetry unit and an MP telemetry unit), sensor systemsetc. Which telemetry units, sensor systems etc. are powered at any giventime may be determined by a configuration file for power controller 90.

In some embodiments, power controller 90 comprises or is connected toreceive an output from a pressure sensor 94. Pressure sensor 94 sensespressure within the drill string. This pressure typically varies withdepth in the wellbore. Power controller 90 may be configured to controlpower to certain sub-systems or controllers based on the output ofpressure sensor 94. For example, power controller 90 may be configuredto inhibit operation of the EM telemetry sub-system (e.g. by cutting offpower to all or part of the EM telemetry sub-system) when housing 51 isat or near the surface (for example, by detecting an output frompressure sensor 94 indicating low pressure). This feature may improvesafety by avoiding charging the exterior of housing 51 to significantvoltages while housing 51 is at or near the surface.

Power controller 90 may optionally provide readings of pressure sensor94 to other controllers either in response to requests from the othercontrollers or otherwise. In some embodiments, power controller 90 orone or more other controllers may be configured to switch system 50among a number of different operational modes in response to changes inthe readings from pressure sensor 94. For example, the differentoperational modes may transmit different data to the surface and/ortransmit that data using different arrangements of one or more telemetrysub-systems. For example, for some depths system 50 may use EMtelemetry, for other depths system 50 may use MP telemetry, at otherdepths, system 50 may use both EM and MP telemetry concurrently.

Power controller 90 may be connected to operate switches that connect ordisconnect other parts of apparatus 50 from battery power. For example,when apparatus 50 is operating in a mode in which one telemetry systemis not used, power management controller 90 may disconnect the supply ofelectrical power to the telemetry subsystem (including its controller).In a period when sensors are not being read, power management controller90 may disconnect electrical power to the sensors and/or an interface tothe sensors (e.g. interface sensor controller 60).

In some embodiments a separate power controller is not required. Thefunctions of power controller 90 may be combined with those of anothercontroller and/or distributed among other controllers in apparatus 50.For example, a controller may act as a power controller for an EMtelemetry subsystem 75 and a sensor interface 60 as well as act as acontroller for an MP telemetry subsystem.

FIG. 3A shows an example embodiment in which a power control system 95includes a power controller 90 connected to control operation ofswitches A1, A2, A3 and A4. A1 controls power to RX Unit and sensorinterface 60. A2 controls power to EM system 75. A3 controls power toflow sensor 54. A4 controls power to pulser unit 80. Additional switches(not shown) may be provided to control connection of electrical power toother circuits of a downhole system.

The various controllers of control system 42 may be in communication viaa data communications bus, such as a CAN (controller area network) bus98. In other embodiments, the controllers may be in communication viaany other suitable protocol, on physical or wireless networks, or in anyother manner now known or later developed.

A downhole system according to any of the embodiments described hereinmay be in communication with other sensors, systems, components, devicesor the like via data bus 98 or otherwise. For example, control system 42may also, or alternatively, be in communication with a near-bit tool,which may provide to control system 42 measurements taken near to drillbit 14. Such measurements may be transmitted by telemetry system 40 inany of the ways disclosed herein.

In some embodiments, control circuitry (such as control system 42 anddata bus 98) and other devices (such as capacitor bank 92) areintegrated onto one or more short (e.g. 12-inch-long) carrier boards,together constituting a control system inside of housing 51. In someembodiments, the components of telemetry apparatus 50 are arranged inthe following sequence: valve 86, motor 84, control system, sensorsystem 64, direction and inclination sensor 62, and battery 96. Suchembodiments may be used in either orientation (i.e. valve 86 positionedon either the uphole or downhole end), but positioning valve 86 on thedownhole end of the probe may reduce damage from the flow of drillingfluid on the seals of the probe.

It can be appreciated that at least some embodiments provide a singleset of sensors and a system for managing data from the sensors whileproviding the flexibility to transmit any of the data by way of any oneor more of a plurality of different telemetry links. In some embodimentsdata (whether the same data or different data) may be transmittedconcurrently on two or more telemetry links. In some embodiments thesystem has a configuration which permits each of two or more telemetrysystems (which may operate using physical principles different from oneanother) to operate independently of one another. A power managementsystem may control the supply of power to the telemetry links from acommon power source or set of power sources thereby facilitating betterpower management than would be possible if each telemetry link waspowered from a separate source.

Example Data Transmission Methods and Configurations

In an example embodiment, a downhole system as described herein can beconfigured to transmit data in any of a number of different modes whichdiffer from one another in respect of which telemetry systems areavailable and/or which telemetry systems are used to transmit dataand/or in cases where more than one telemetry systems are available totransmit data which data is transmitted using each telemetry systemand/or which parts of the downhole system are powered off.

Example Telemetry Modes

Different modes may specify the use of different telemetry systems orcombinations of telemetry systems to transmit telemetry data.

EM-Only and MP-Only Modes

For example, a downhole system as described herein such as system 40 or40A or 50 may have an EM-only mode (in which only an EM telemetrysystem—e.g. 46A, 75 is used to transmit data), an MP-only mode (in whichonly an MP telemetry system 46B, 85 is used to transmit data), or aconcurrent telemetry mode (in which both the EM and MP telemetry systemsare active and available to transmit data and may transmit dataconcurrently). In some embodiments, EM telemetry system 46A or 75 ispowered down when system 40 is in MP-only mode and MP telemetry system46B or 85 is powered down when system 40 is in EM-only mode.

Use of an EM-only mode can be particularly advantageous during timeswhere there is no flow of drilling fluid (“Flow-off” conditions). Atthese times electrical interference is minimized and MP telemetry is notpractical. EM telemetry may be used during these periods, for example,for rapid transmission of survey data. Sending survey data duringpump-off conditions avoids delays waiting for survey data to betransmitted by MP telemetry after fluid flow is resumed. Furthermore,during pump-off conditions EM telemetry is typically least affected bynoise and can be achieved from deeper depths and/or using lower powerthan would be required to transmit the same data while drilling is inprogress. Use of an MP-only mode can be particularly advantageous whileactive drilling is occurring.

Concurrent Telemetry Modes

When transmitting data in a concurrent telemetry mode, the telemetrysystem 40 may be configured to transmit in a concurrent confirmationmode wherein the same telemetry data or closely similar but differenttelemetry data is transmitted by both of the EM and MP telemetrysystems, or in a concurrent shared mode wherein some of the telemetrydata is transmitted by the EM telemetry system, and the rest of thetelemetry data is transmitted by the MP telemetry system. Combined modesare also possible (for example certain data may be transmitted by bothof the EM and MP telemetry systems while other data is transmitted onlyby one of the EM telemetry system and the MP telemetry system). In otherembodiments, modes of telemetry other than EM and MP telemetry may beused alone or in combination with MP and/or EM telemetry modes and/or incombination with one another.

Concurrent Confirmation Mode

The concurrent confirmation mode permits surface equipment (e.g. surfacetransceiver 26) or operators to compare the same data that has beentransmitted by both telemetry units 46A, 46B or 75, 85 and which can bereceived and compared to each other at surface. In the concurrentconfirmation mode, EM telemetry 46A and MP telemetry 46B are configuredto transmit the same data roughly concurrently. The recipient of thesetwo signals (e.g. surface equipment or an operator on the surface) canthen decode them and compare the data transmitted by each of thetelemetry systems 46. If the data matches, the recipient may take thatas an indication that telemetry systems 46 are operating correctly. Ifthe data does not match, then the recipient may attempt to correct itsdecoding methods or apparatus or may conclude that one or more oftelemetry systems 46 is not operating correctly. In this way, aconcurrent confirmation configuration profile may serve as a “systemtest” mode, or may offer additional redundancy when critical data isbeing transmitted. This is discussed in greater detail below withreference to FIG. 14.

In a concurrent confirmation mode, one of the telemetry units 46A, 46Bor 75, 85 may be designated to be the primary or main transmitter. Insome embodiments the MP telemetry unit 46B, 85 is set as the defaultprimary transmitter. The controller for the primary telemetry unit maycontrol requests for measurements to the sensors (e.g. sensors 54, 56,58, 62, 64, 66, 94) and mirror the received measurement data to thecontroller for the other telemetry unit. In some embodiments, the flowand RPM sensor measurement data may be used to trigger transmission ofEM and MP telemetry data.

In some embodiments data sent in a concurrent confirmation mode bydifferent telemetry units may be similar but different. For example,data sent on one telemetry unit may include a parameter value sampled ata first time and data sent on another telemetry unit may comprise thesame parameter value sampled at a second time different from the firsttime. In an example embodiment the first and second times are within afraction of a second (e.g. within 100 ms or 50 ms) of one another.

A concurrent confirmation mode may be useful for determining which oftwo or more telemetry systems is better under current drillingconditions. Each system may transmit the same data at its own speed. Thefunctionality of each telemetry system may be fully exploited. Criticalinformation will be transmitted to the surface even if one telemetrysystem is not working well in the current drilling conditions.

Another application of concurrent confirmation mode is to test whether aparticular telemetry system can be used effectively while ensuring thatthe necessary data will be received by transmitting the same data onanother telemetry system. For example, when drilling an exploratory wellit may not be known whether downhole conditions are amenable to EMtelemetry. With EM and MP telemetry systems operating in a concurrentconfirmation mode drilling can proceed even if EM telemetry proves to beimpractical given the downhole conditions. If it turns out that the EMtelemetry is functioning well then the speed advantage of EM telemetryover MP telemetry may be applied to allow the well to be drilled faster.

In embodiments where a downhole system has backup sensors (e.g. backupsensors 67), in some embodiments a downhole system operating in aconcurrent confirmation mode is configured to send data from mainsensors using one telemetry system and corresponding data from thebackup sensors using another telemetry subsystem. This permitsverification of the reliability of the sensor readings themselves. In analternative mode, one telemetry subsystem may send averages of readingsfrom main and backup sensors and the other telemetry subsystem may sendreadings from one or both of the main and backup sensors.

In some embodiments, a downhole system operating in a concurrentconfirmation mode is configured to obtain data representing a value ofone sensor at two spaced apart times and to transmit one of theresulting values using a first telemetry subsystem and another of theresulting values using a second telemetry subsystem. Since the valuesmay be obtained at closely spaced apart times, comparison of the valuesmay be used to assess the reliability of data transmission. In this modethe surface equipment can obtain faster sampling of the values of thesensor output than it would receive using a concurrent confirmation modein which the same sensor reading was transmitted twice once by each oftwo different telemetry subsystems. This technique may be used, forexample, to transmit values from higher density gamma logging.

Example Application of Concurrent Confirmation Mode

For transmissions made in the concurrent confirmation mode and referringto FIG. 14, the surface transceiver 26 and computer 32 may process anddecode each EM and MP telemetry signal into their respective measurementdata sets. The computer 32 may perform an error check bit matchingprotocol against each decoded data set and then assign a confidencevalue to each data set. The computer 32 may use error check bit matchingprotocols known in the art, such as a 1 bit parity check or a 3 bitcyclic redundancy check (CRC). More particularly, the downhole telemetryapparatus 50 may add CRC bits to the telemetry signal e.g. at the end ofthe telemetry signal (“telemetry data bits”), and the decoders of thesurface transceiver 26 may be provided with the matching CRC bits(“error check bits”) that will be compared to the CRC bits in thetelemetry signals to determine if there were errors in the telemetrysignal.

In one embodiment, each data set can be assigned one of three confidencevalues corresponding to the following:

-   -   High confidence—telemetry data bits match error check bits.    -   Medium confidence—telemetry data bits only match error check        bits after modification of selected thresholds, e.g. amplitude        threshold.    -   No confidence—telemetry data bits do not match error check bits,        even after modification of selected thresholds.        The surface transceiver 26 may determine the signal to noise        ratio of each received EM and MP telemetry in a manner that is        known in the art.

The surface transceiver 26 may then compare the EM and MP data sets, anddetermine whether the data sets are sufficiently similar to meet apredefined match threshold; if yes, then the data sets are considered tomatch. More particularly, when both data sets are encoded using the samenumber of bits, the decoded data sets should have an exact match. Insome embodiments the same or similar data values are encoded to a firstprecision using a first number of bits for transmission on a firsttelemetry subsystem or mode and are encoded to a second precision usinga second number of bits for transmission by a second telemetry subsystemor mode. When the data sets are encoded using different numbers of bitsto represent the same measurement data, the match threshold is met solong as the error between the two decoded data sets is within aspecified range, e.g. less than the difference between a 1 bit change.

When the two data sets match and both have at least a medium confidencevalue, then either data set can be used to recover the measurement data.When the EM and MP data sets do not match, and both EM and MP data setsare assigned the same high or medium confidence value, the surfacetransceiver 26 may select the data set having the highest detectedsignal-to-noise ratio. When the EM and MP data sets do not match and theMP and EM data sets are assigned different confidence values, thesurface transceiver 26 may select the data set having the highestconfidence value. When both the EM and MP data sets are assigned a noconfidence value, the surface transceiver 26 may output a “no data”signal indicating that neither data set is usable.

Concurrent Shared Mode

The concurrent shared mode operates like two separate telemetry systems.In this mode, each of the EM and MP telemetry units 46A and 46B or 75,85 may be configured to obtain certain measurement data from sensors(e.g. some or all of sensors 54, 56, 58, 62, 64, 66, 94) and encode andtransmit this data. For example, EM controller 70 may be configured toread gamma, shock and vibration measurements and encode thesemeasurements into an EM telemetry signal, and MP controller 80 may beconfigured to read toolface measurements and encode these measurementsinto an MP telemetry signal.

A downhole system may be configured to cause more critical measurementdata to be transmitted by the telemetry subsystem which is expected tobe more reliable or faster during the present drilling conditions, andless critical measurement data to be transmitted by the other telemetrysubsystem. Reliability of different telemetry subsystems may be measuredon an ongoing or periodic basis. Which telemetry subsystem is faster ormore reliable may change as depth and other drilling conditions change.

An example method that may be applied for assessing the relativereliability of telemetry data and selecting a telemetry mode based onthat assessment is described below in relation to FIG. 14. In someembodiments, a telemetry subsystem is configured to periodicallytransmit predetermined test transmissions and the reliability of thedata channel carried by the telemetry subsystem is evaluated by decodingthe test transmissions and comparing the decoded test transmissions tothe known content of the test transmissions. Such test transmissionsmay, additionally or in the alternative, be applied to monitorvariations in attenuation of the transmitted telemetry system with depthin the wellbore. Such attenuation information may be applied to controlthe transmission of telemetry signals to compensate for such attenuationwhile conserving electrical power when possible.

As another example, where measures of reliability and timeliness(latency) for different telemetry modes is available, data may beallocated among the telemetry modes based on different factors fordifferent data types. For example, for a first data category highconfidence in the decoded data may be a primary concern. Data in thefirst data category may be transmitted using the telemetry mode forwhich the reliability measure indicates highest confidence in thetransmitted data. For a second data category timeliness may be a primaryconcern. Such data may be transmitted using the telemetry mode for whichthe timeliness measure indicates lowest latency.

In some embodiments there is a third category of data for which bothhigh confidence in the decoded data and timeliness are important. Thethird category is not necessarily distinct from the first and/or secondcategories. In such cases data in the third category may be transmittedusing two telemetry modes, a faster but less reliable mode and a slowerbut more reliable mode. In some such embodiments, surface equipmentdecodes the data transmitted by the faster but less reliable mode whenthat data is received and makes that decoded data available. When thesame data is received by the slower but more reliable mode the surfaceequipment may update the data, particularly if the decodedsecond-received data differs from the less-reliable first-received data.Where the data is displayed on a display the display optionally includesan indication as to the level of reliability of the data currently beingdisplayed. In some embodiments the display includes an indication as towhether or not and/or when more-reliable data is expected to beavailable for display.

In some embodiments, allocation of data to different telemetrysubsystems comprises assigning a set of data for transmission to onetelemetry subsystem. The set of data may be ordered according topriority with most-important data first. A time limit may be pre-set forcompleting transmission of the set of data. If it becomes apparent thattransmission of the set of data will not be completed by the time limitthen some of the set of data may be redirected for transmission on analternative telemetry subsystem. In addition or in the alternative, aminimum bit-rate may be set for transmission of the set of data. If theminimum bit rate is not met by the assigned telemetry subsystem thensome of the set of data may be redirected for transmission on thealternative telemetry system.

In one embodiment of the concurrent shared telemetry mode, one telemetryunit 46A, 46B or 75, 85 will transmit its telemetry signal regardless ofwhether the other telemetry unit 46A, 46B or 75, 85 is functioning orhas failed. As described in more detail herein, a downhole system may beconfigured to switch telemetry modes in response to receipt of adownlink command from a surface operator, such as a command to switchfrom the concurrent shared mode to the MP-only mode when the operatordetects that the EM telemetry unit 75 has failed. In another embodiment,a telemetry unit 75, 85 which has failed or is not functioning properlyis programmed to send a signal over data bus 98. The other telemetryunit 75, 85 which is still functioning may, upon receipt of this signal,be configured to change to an operating mode in which it obtainsmeasurement data from sensors (e.g. sensors 54, 56, 58, 62, 64, 66, 94)which were supposed to be obtained by the failed telemetry unit 75, 85in addition to the measurement data the functioning telemetry unit hasalready been configured to obtain.

In another example of a concurrent mode, EM and MP telemetry units 46A,46B or 75, 85 may be configured to transmit only some of the samemeasurement data (e.g. toolface data). This can be useful when it isdesirable to verify the accuracy of certain data. In some embodimentsthe respective EM and MP telemetry units are configured to obtain thesame measurement data at the same time, i.e. to synchronize theirreading of the measurement data from the relevant sensors.

In one example of a telemetry mode, survey data (e.g. survey dataacquired by one or more sensors 54, 56, 58, 62, 64, 66, 94) can betransmitted by EM telemetry unit 46A or 75, wherein the survey data isencoded into an EM telemetry signal and transmitted by the EM telemetryunit 46A or 75 during a drill string idle time, during a period of nomud flow and no drill string rotation. After the survey data has beentransmitted, the EM telemetry unit 46A or 75 may power off and othermeasurement data may be transmitted by MP telemetry unit 46B or 85.

Data Unit Splitting e.g. Byte Splitting

Another type of concurrent shared mode transmits parts of individualdata elements using different telemetry units. This approach can help toameliorate the problem that data rates of all telemetry modes can becomevery low when drilling deep wells. Consider, for example the case wherea telemetry system takes 5 seconds per bit to transmit certain data tothe surface from a certain downhole location and the data in question is12 bits. In this example, it will take at least 5×12=60 seconds totransmit the data using the telemetry system. The data may, for example,be a value of a single sensor reading.

If a second telemetry system is available then the latency (time betweenthe sensor reading being made and the sensor reading being available atthe surface) can be reduced by transmitting some of the bits using eachof the telemetry systems. For example, if the second telemetry systemcan also transmit data from the downhole location at a rate of 5 secondsper bit then each telemetry system may be configured to transmit 6 bitsof the data. In this mode, the time taken to transmit the data may bereduced to 5×6=30 seconds. Thus, splitting a single data element betweentwo or more telemetry channels (e.g. between an EM telemetry channel andan MP telemetry channel) may result in dramatically reduced latencywhich may, in turn, provide closer to real-time control over thedrilling operation. This mode may be called a “concurrent sharedbyte-splitting” mode (even though the data units being split are notnecessarily 8-bit bytes).

In some embodiments a data unit being split is a single number (e.g. abinary number encoding one or more parameter values). In someembodiments the data unit being split comprises an error detectingand/or error correcting code. For example one or more check bits. Forexample, the data unit may comprise a parity bit, a number of CRC(cyclic redundancy check) bits, or the like in addition to data bits. Inan example embodiment a data unit comprises 7 data bits representingdata such as toolface data and 3 CRC bits for a total of 10 bits. Insome embodiments the data unit comprises 33 or fewer bits. In someembodiments the data unit comprises 7 to 15 bits. In some embodiments anentire data unit or element is required to effectively use the data unitand/or to check the data unit for errors and/or to correct errors in thedata unit.

In some embodiments a concurrent shared byte-splitting mode is used totransmit toolface data. In some embodiments toolface data is transmittedin a manner that varies with available data rates. For example, while afirst telemetry subsystem (e.g. an MP subsystem) can transmit toolfacedata at a high rate, then high resolution toolface data may betransmitted using the first telemetry subsystem. If the available datarate drops below a threshold then the high resolution toolface data maybe split, some bits of the toolface data may be transmitted using thefirst telemetry subsystem and other bits of the toolface data may besent using a second telemetry subsystem (e.g. an EM subsystem). If thedata rate drops still further then lower resolution toolface data may betransmitted (again splitting the bits between the first and secondtelemetry subsystems). In one example embodiment, the high resolutiontoolface data is 11 bits and the low resolution toolface data is 7 bits.In either case, some data error detecting/correcting bits may also beprovided.

In some embodiments the bits of a data unit are allocated amongtelemetry subsystems in proportion to the bit rate at which thetelemetry systems can operate. For example, if from a certain locationan EM telemetry subsystem is operable to transmit data at a rate of 5bits every 10 seconds and an MP telemetry subsystem is operable totransmit data at a rate of 10 bits every 10 seconds then, to minimizelatency of a 12-byte data unit, 8 bytes may be transmitted by way of theMP subsystem and 4 bytes may be transmitted by way of the EM telemetrysubsystem.

To facilitate a concurrent shared byte-splitting mode a controller in adownhole system may be configured to obtain a sensor reading and toforward parts of the sensor reading to each of two or more telemetrysystems for transmission. As another example, the controller may beconfigured to forward the entire sensor reading to each of the pluralityof telemetry systems and each telemetry system may be configured totransmit a corresponding portion of the sensor reading. As anotherexample, each telemetry system may be configured to obtain the sensorreading and to transmit a corresponding part of the sensor reading.

A range of schemes may be applied to allocate specific bits of a dataunit among telemetry subsystems. For example, the bits may be allocatedusing a round robin scheme such that each of a plurality of telemetrysubsystems is allocated one bit or one group of two or more bits inturn. For example, with two telemetry subsystems operating, a first oneof the telemetry subsystems may transmit the bits for every odd bitposition in the data unit and a second one of the telemetry subsystemsmay transmit the bits for every even bit position of the data unit.

As an alternative, high-order bits of the data unit may be transmittedby the first telemetry subsystem and low-order bits may be transmittedby the second telemetry subsystem. In this case, the reliability of thedata transmissions of the telemetry subsystems may optionally be used todetermine which telemetry subsystem is used to transmit the higher orderbits of the data unit and which telemetry subsystem is used to transmitthe lower-order bits of the data unit. For example, the more reliable(lower error rate) telemetry subsystem may be used to transmit the lowerorder bits in cases where the higher order bits are less likely tochange between subsequent sensor readings.

The allocation of bits of certain data units among a plurality oftelemetry subsystems may be done according to a predeterminedconfiguration profile (as discussed below). In other embodiments,allocation of bits of certain data units among telemetry subsystems maybe set up using downlink commands or set up automatically at a downholesystem (which may then communicate this bit allocation to surfaceequipment using one or more of the telemetry systems). The surfaceequipment is configured to receive, decode and combine the bits torecover the transmitted data.

In some embodiments, one or more of the telemetry systems is configuredto transmit symbols that each represent N-bits (where N is less than thesize of a data unit to be transmitted) and the downhole system isconfigured to send N bits of the data unit using the telemetry systemand to send the rest of the data unit using one or more other telemetrysystems.

By being able to operate in a number of different telemetry modes,downhole systems as described in the present examples offer an operatorflexibility to operate the system in a preferred manner. For example,the operator can increase the transmission bandwidth of the telemetrytool by operating in the concurrent shared mode, since both the EM andMP telemetry systems are concurrently transmitting telemetry datathrough separate channels. Or, the operator can increase the reliabilityand accuracy of the transmission by operating in the concurrentconfirmation mode, since the operator has the ability to select thetelemetry channel having a higher confidence value. Or, the operator canconserve power by operating in one of MP-only or EM-only telemetrymodes. Or the operator can reduce latency for transmission of individualparameters or other blocks of information by operating in a‘byte-splitting’ mode.

Further, the operator can choose the MP-only or EM-only modes based onwhich mode best suits the current operating conditions; for example, ifthe reservoir formation requires an EM telemetry system to transmit at avery low frequency in order for an EM telemetry signal to reach surface,the resulting low data rate may prompt the operator to select totransmit using the MP-only mode. Conversely, when there is no mudflowing (e.g. while air drilling), the operator can select the EM-onlymode to transmit telemetry data. The flexibility of downhole systemsaccording to preferred embodiments described herein facilitatesconfiguring such downhole systems to promote benefits such as: fasterdata communication, better energy efficiency, more reliable datacommunication; and/or more flexible data communication.

Testing Modes

Some embodiments provide testing modes for different telemetry systems.In such a testing mode a telemetry system may be operated to transmitpredetermined data for receipt and analysis at the surface.

By offering a variety of different telemetry modes in which telemetrysignals can be transmitted by the telemetry apparatus 50 and received bythe surface transducer 26, the telemetry system offers an operator greatoperational flexibility. The telemetry apparatus 50 can be instructed totransmit at the highest data rate available under current operatingconditions; for example, if the telemetry apparatus 50 is at a locationthat the EM telemetry unit 75 must transmit an EM telemetry signal at avery low frequency in order to reach surface and which results in a datarate that is lower than the data rate of the MP telemetry unit 85, thesurface operator can send a downlink command to instruct the telemetryapparatus 50 to transmit using the MP telemetry unit 85. Further, thetelemetry apparatus 50 can be instructed to transmit in one telemetrymode when the operating conditions do not allow transmission in theother telemetry mode; for example, the telemetry apparatus 50 can beinstructed to transmit in the EM-only telemetry mode when no mud isflowing. Further, the telemetry apparatus 50 can be operated in aconcurrent shared mode effectively doubling the number of telemetrychannels thereby increasing the overall data transmission bandwidth ofthe telemetry apparatus 50. Further, the reliability of the telemetryapparatus 50 can be increased by transmitting in the concurrentconfirmation mode and selecting the telemetry data having the highestconfidence value. Further, if one telemetry subsystem fails or is notuseable in current conditions then another telemetry system may be usedto allow continued drilling.

Surface Equipment Synchronization

To decode transmissions received from a downhole system, surfaceequipment needs to know the way in which the data has been encoded. Thismay be done in a variety of ways. For example:

-   -   In some embodiments, the specific data to be encoded by the        downhole system and the way in which that data is encoded is        predetermined. The downhole system is configured to transmit the        data using the predetermined scheme and the surface equipment is        configured to decode the data using knowledge of the        predetermined scheme.    -   In some embodiments different groups of data are transmitted by        the downhole system according to different predetermined        schemes. Surface equipment may be configured to decode the data        and to determine which scheme has been used for each set of        received data based on information in the data (e.g. a frame        header, an ID code, or the like).    -   Encoding schemes may be selected and/or set up after the        downhole system has been deployed. This may be done, for        example, when the downhole system is relatively near to the        surface and so reliable relatively high bandwidth communication        is available. In some such embodiments, telemetry information        such as one or more aspects of data selection and/or encoding        methods for data and/or telemetry mode and/or data ordering may        be determined at the downhole system and transmitted to the        surface equipment. This transmission may be done using a        predetermined protocol. For example, the surface system may be        configured to wait for a binary status message that indicates        how the surface system should decode received telemetry        transmissions. The telemetry information may be subsequently        used by the surface equipment to decode telemetry data received        by the surface equipment.    -   In some embodiments, a single telemetry subsystem (e.g. an EM        telemetry subsystem) may be used to transmit telemetry        information for all or a group of telemetry subsystems. In some        embodiments the downhole system may determine the telemetry        information based in part on the operational status and        availability of telemetry subsystems.    -   In some embodiments, one telemetry subsystem may be used to        transmit telemetry information for another telemetry subsystem        and vice versa. For example, an EM telemetry subsystem may be        used to transmit to surface equipment telemetry information        required for decoding telemetry data from a downhole MP        telemetry subsystem and an MP telemetry subsystem may be used to        transmit to surface equipment telemetry information required for        decoding telemetry data from a downhole EM telemetry subsystem.    -   The downhole system may transmit status messages that indicate        changes in telemetry modes, what data is being transmitted, how        that data is formatted, whether byte-sharing is occurring,        and/or other data required or useful for decoding the telemetry        data at the surface.

In an example embodiment an EM telemetry system is used to transmitinformation regarding the encoding of data transmitted by an MPtelemetry system. This may significantly reduce the amount of timerequired to start receiving and decoding data by way of the MP telemetrysystem. In the case where there are a plurality of available EMtelemetry channels (e.g. two EM telemetry systems are downhole)optionally one EM telemetry channel may be dedicated to providingtelemetry information for other telemetry channels (e.g. for an MPtelemetry channel and/or for another EM telemetry channel). The controlinformation may be encoded and transmitted, for example, according to apredetermined format.

Telemetry information in any embodiment may comprise, for example, anindex identifying a predetermined configuration profile, data indicatingan encoding scheme, data indicating a telemetry mode, and/or other datathat provides information necessary or useful for detecting and/ordecoding at the surface equipment received telemetry transmissions.

Mode Switching

A downhole system (e.g. 40, 40A, 50) may be caused to shift among theavailable modes in various ways. These include:

-   -   receiving a downlink command from surface equipment;    -   receiving user input prior to deployment of the downhole system;    -   automatically changing modes in response to detected drilling        status;    -   automatically changing modes in response to one or more        measurements collected by sensors of the downhole system;    -   automatically changing modes in response to the status of the        downhole system (e.g. power availability, failure of a        component, activation or deactivation of one or more sub-systems        of the downhole system—for example, an EM telemetry system, an        MP telemetry system etc.). Deactivation of a subsystem of a        downhole system may be due to, for example, damage, malfunction,        an automated process, user instruction, intentional or        unintentional power loss, conditions that impair the        effectiveness of the telemetry system and/or any other reason);    -   automatically changing modes in response to conditions affecting        one or more telemetry systems (e.g. excessive current draw for        an EM telemetry system, insufficient flow for an MP system);    -   automatically changing modes at predetermined times; and,    -   combinations of these.

In some embodiments the downhole system may be configured to performtelemetry in a certain way or ways by loading one or more configurationprofiles at the surface. The tool may then operate in one configurationfor an entire downhole deployment. In other embodiments the downholesystem may be configured to switch among two or more different modes inresponse to commands from the surface (whether transmitted by a downlinktelemetry system or through predetermined patterns of operation of thedrill string and/or drilling fluid system) and or automatically inresponse to certain events and or conditions.

In some embodiments a downhole system is loaded with configurationinformation that specifies each of a sequence of operating modes in apredetermined order. In such embodiments a very short command maysuffice to control the downhole system to switch to a next one of thesequence of modes.

In some embodiments, downlink commands are provided by downlink EMtelemetry.

In some embodiments, switching among different modes is achieved byswitching among corresponding configuration profiles which specify theattributes of the different modes as described in more detail below.

Where a telemetry subsystem is reconfigured to transmit data in adifferent way (e.g. to change an encoding scheme, the format in whichdata is presented in telemetry signals, etc.) the surface equipment mustalso be reconfigured to properly decode received telemetry signals.Given the problems of communicating with a downhole system atsignificant depths there can be cases where it is unknown whether adownlink command has been received and acted on by a downhole system. Insome embodiments, when a downhole system reconfigures one telemetrysubsystem, the downhole system is configured to transmit confirmationinformation on another telemetry system that confirms the change. Theconfirmation information may optionally include information thatspecifies or identifies the new mode. For example, when an EM system isreconfigured to a lower frequency and/or a different number of cyclesper bit and/or a different encoding scheme, information may betransmitted to the surface equipment by an MP telemetry subsystem thatconfirms that the EM telemetry subsystem is now reconfigured. Similarly,an EM telemetry subsystem may be used to send confirmation informationconfirming that an MP telemetry subsystem has been reconfigured.

Example Applications of Mode Switching Example 1

In one example embodiment, a downhole system 40, 40A, 50 is configured(e.g. by suitable software) to start operating initially using aselected telemetry mode, and to change to a different telemetry mode inresponse to a downlink command from surface equipment.

Example 2

In another example embodiment, in a first mode EM telemetry system 46Aand MP telemetry system 46B are both active and available fortransmission. The first mode may be a ‘concurrent shared’ mode in whichEM telemetry system 46A is configured to transmit the most recentmeasurements from direction and inclination system 62, together withmeasurements from one or more of the remaining sensors. In the firstmode MP telemetry system 46B may be dedicated solely to the transmissionof the most recent measurements from gamma sensor 64. In the first modetelemetry systems 46 transmit data independently so as to obtain acorresponding increase in the total bandwidth of telemetry system 40.

Further, in this example, control system 42 may be configured such that,if MP telemetry system 46B is deactivated or if an appropriateinstruction is received from the surface, then control system 42 mayswitch to a second “EM-only” mode. Control system 42 may send a statusmessage prior to switching modes. The status message informs surfaceequipment of the change in mode.

In the EM-only mode the downhole system may be configured to cause EMtelemetry system 46A to transmit the most recent measurement from gammasensor 64 on every other frame (e.g. on odd numbered frames), leavingthe remaining (e.g. even numbered frames) to be used for other desireddata. In the alternative, the second mode may configure telemetrysystems 46 to operate independently such that, in the event that onetelemetry system 46 is deactivated, the remaining telemetry system(s) 46continue to operate without changing their behaviour. A change inbehaviour may still be caused by, for example, transmission of aninstruction to change configuration profiles from the surface to thebottom hole assembly.

Control system 42 may, in response to certain sensor readings disable orsuspend operation of one or more telemetry systems. For example thesystem may include a sensor connected to measure current of an EMsignal. If the current exceeds a threshold then the EM system may beshut down or placed in a non-transmitting mode. In this event the systemmay automatically switch over to an “MP-only” configuration profile. TheMP only profile may both specify that the EM system should be shut offor inhibited and specify data to be transmitted by MP telemetry in aspecific sequence.

Other sensor readings that may prompt a change in configuration profilemay, for example, include failing to detect MP pressure pulses at adownhole pressure sensor or receiving pressure sensor readings thatindicate that a valve used for generating MP pulses is jamming orotherwise malfunctioning. Control system 42 may be configured to switchover to an “EM only” configuration profile in response to detecting suchsensor readings. The EM only profile may both specify that the MP systemshould be shut off or inhibited and specify specific data to betransmitted by EM telemetry in a specific sequence.

In some embodiments, control system 42 may automatically change profilesin response to such a sensor reading. In some embodiments, such a sensorreading may result in the transmission of one or more “status” frames tothe surface indicating the sensor reading; this enables a surfaceoperator to respond with an instruction to change configurationprofiles.

In some embodiments a system may be configured to use MP telemetry onlyand to switch to EM telemetry in the event that the MP system is notable to function properly (either because of a malfunction or due todownhole conditions being unsuitable for MP telemetry). More generally,in some embodiments a system may be configured to use a first telemetrymode only and to switch to another telemetry mode if the first telemetrymode is not able to function at at least a minimum performance level.

Example 3

In another example, the downhole system (or surface equipment) isconfigured to periodically determine the cost per bit of datatransmitted of a plurality of available telemetry subsystems. The costmay be measured in terms of energy consumption and/or efficiency (e.g. acost penalty may be applied to a telemetry subsystem that has a slowdata rate or is unreliable). Based on the cost information the downholesystem may automatically be switched between different operating modes(e.g. an EM-only mode, an MP-only mode, any of various shared modeswhich may differ in the total amount of data to be transmitted and/orthe allocation of that data between an EM telemetry subsystem and anMP-telemetry subsystem).

As another example, a user of the downhole system may pay differentrates for data transmitted by different telemetry subsystems. Based oneconomic cost information the downhole system may be switched manuallyor automatically between different operating modes. For example, thedownhole system may automatically switch to a lower-cost telemetry modeor switch an allocation of data so that less data is sent on ahigher-cost telemetry mode when a budget has been reached fortransmitting data using the higher-cost telemetry mode. In someembodiments the higher-cost telemetry mode is an EM telemetry mode.

Configuration Profiles

In some embodiments, configuration profiles are used to facilitatespecifying the particular characteristics of different operating modesand to facilitate switching among two or more different modes. Aconfiguration profile comprises information that may be storedelectronically. The information may comprise software instructions forexecution by one or more controllers and/or data such as flags,parameter values, settings, or the like that can be applied to alter theoperation of a downhole system. Telemetry apparatus 50 may contain a setof configuration profiles stored in one or more data stores. Theconfiguration profiles may configure many aspects of the operation ofapparatus 50. The operation of apparatus 50 may then be changed byswitching from one configuration profile to another. In some embodimentsa configuration profile comprises separate sets of instructions and/ordata for each of a plurality of controllers. Each controller may operateas determined by the corresponding set of instructions and/or data.

Configuration profiles may be stored in data storage 204, or in someother memory or location accessible to one or more controllers ofcontrol system 42.

For example, different configuration profiles may respectively configureapparatus 50 to operate in: 1) an MP-only telemetry mode, wherein onlythe MP telemetry unit 85 is used to send telemetry signals via mudpulses; 2) an EM-only telemetry mode, wherein only EM telemetry unit 75is used to send telemetry signals via EM signals; 3) a concurrent sharedtelemetry mode wherein both EM and MP telemetry units 75, 85 are usedconcurrently to transmit data, and wherein some of the data is sent byEM telemetry signals and the rest of the data is sent by MP telemetrysignals; and 4) a concurrent confirmation telemetry mode, wherein bothEM and MP telemetry units 75, 85 are used to transmit the same data.Apparatus 50 may be placed into any one of these modes by making thecorresponding configuration profile active.

A configuration profile may include executable instructions and/or datawhich are collectively executed and/or interpreted by apparatus 50 tocause apparatus 50 to perform in a manner specified by the configurationprofile. The ability to change the operation of apparatus 50 usingelectronically storable configuration profiles enables apparatus 50 tobe readily reconfigured to work in a wide range of applications.

In some embodiments configuration profiles may comprise software and/orsettings to be executed/interpreted by specific ones of controllers 52,60, 70, 80, and 90. Switching between different configuration profilesmay involve executing a routine which makes software and/or settingsassociated with a new configuration profile active. Differentconfiguration profiles may, inter alia, specify different telemetrymodes. Each of the configuration profiles may cause telemetry apparatus50 to generate telemetry signals according to a corresponding selectedoperating configuration specified by instructions and/or settings in theconfiguration profile. The configuration profiles may, for example,specify factors such as:

-   -   the telemetry mode in which telemetry apparatus 50 may operate        (e.g. which telemetry systems will be used, what data will be        acquired and transmitted on each telemetry system);    -   the type(s) of message frames to be sent in the telemetry        transmission(s);    -   the composition of the message frame(s), which may include the        data type, timing, and/or order of the data in each message        frame, specification of any error-correction protocol; and    -   one or more modulation schemes to be used to encode the data        into telemetry signals.

A set of configuration profiles may include a plurality of configurationprofiles which all specify the same general telemetry mode (e.g. MP-onlyor EM-only, etc.). Each configuration profile for that telemetry modemay specify different operating parameters for that telemetry mode. Forexample, in an EM-only telemetry mode, one configuration profile can beprovided with instructions for the telemetry apparatus 50 to encodemeasurement data using one type of modulation scheme (e.g. QPSK) andanother configuration profile can be provided with instructions for thetelemetry apparatus 50 to encode measurement data using a different typeof modulation scheme (e.g. FSK). Or, different configuration profilescan provide instructions for the EM telemetry unit 75 to transmittelemetry signals at different power outputs wherein a suitableconfiguration profile is selected depending on the downhole location ofthe telemetry apparatus 50 and the accompanying attenuation of the earthformation that must be overcome in order for the EM transmission toreach surface.

In some embodiments a default set comprising a plurality ofconfiguration profiles is stored in system 50. For some jobs theconfiguration profiles included in the default set may be adequate.

A custom set of configuration profiles may be downloaded onto telemetryapparatus 50, e.g. when telemetry apparatus 50 is at surface. Loadingconfiguration profiles into apparatus 50 may be performed by way of awired or wireless connection to a host system such as a computer or theinternet or a data store in which the desired configuration profiles areavailable. For example, a connection to a host computer may be made viaa USB cable connected from the computer to an interface port connectedto data bus 98 by a suitable USB interface. As another example,configuration profiles may be loaded into apparatus 50 by inserting oneor more memory cards or other media containing the configurationprofiles into suitable interfaces provided by apparatus 50.

In some embodiments, a set of configuration profiles may be loaded foreach job. The number of configuration profiles loaded into system 50 forany particular job may depend on the expected operations the rig willperform during the job. Once the operator determines which configurationprofiles should form the set of configuration profiles to be downloadedonto the telemetry apparatus 50, a download program on the downloadcomputer may be run to download the selected configuration profiles intoapparatus 50.

In some embodiments the configuration profiles may each comprise aplurality of parts which are designed to be applied by differentcontrollers. For example, a part of a configuration profile may specifyfeatures for EM telemetry transmission and may be intended to be appliedby EM controller 70. Another part of a configuration profile may affectpower management and may be intended to be applied by power controller90 and so on. In some embodiments, apparatus 50 has separate memories ormemory areas for storing software and/or settings for different ones ofcontrollers 52, 60, 70, 80, 90 of the telemetry apparatus 50. In suchembodiments the download program may determine which portion of eachconfiguration profile should be stored for access by each controller andmay then save the different parts of each configuration profile to theappropriate data storage locations in apparatus 50. For example,instructions in the configuration profile relating to operation of theEM telemetry unit 75 may be downloaded only to the memory of the EMcontroller 70.

When a configuration profile is selected, each affected controllerexecutes the applicable software instructions and/or reads theapplicable settings. These instructions/settings cause the controller tocarry out its functions in the manner specified by the configurationprofile. For example, when EM controller 70 executes a configurationprofile portion stored on its memory, the configuration profile mayinclude instructions for whether the EM telemetry unit 75 needs to beactive for the telemetry mode specified in the configuration profile. Ifthe specified telemetry mode requires the EM telemetry to be active(e.g. the specified telemetry mode is EM-only or a combined mode), theEM controller 70 may be configured to read measurements taken by one ormore sensors (e.g. one or more of sensors 54, 56, 58, 62, 64, 66, 94)specified in the configuration profile, encode the measurement data intoan EM telemetry signal using a modulation scheme specified in theconfiguration profile, and cause the components of the EM telemetry unit75 to transmit the EM telemetry signal according to message frameproperties (e.g. type, composition, order, timing) specified in theconfiguration profile.

In some embodiments, a user of drill rig 10 may cause surfacetransceiver 26 to transmit one or more control signals to downholesystem 20, and in particular to a telemetry system 40 of downhole system20, instructing telemetry system 40 to select, add, remove, and/or altera configuration profile, thereby causing the behaviour of telemetrysystem 40 to change the next time the configuration profile is madeactive. This facility may be applied, for example, to correct errors ina configuration profile, compensate for problems caused by failure ofcomponents and/or adverse telemetry conditions, and/or provideinformation required to address a problem encountered in drilling.

Switching Among Configuration Profiles

FIG. 7 shows an example method 310 for changing the currently activeconfiguration profile of a telemetry system 40. Block 312 is the systemstate while no change is being undertaken or considered. When a sensorreading is taken, the method goes to block 314 and receives the sensorreading. The system then considers at block 316 whether a changecondition has been satisfied. A change condition could be, for example,receiving a sensor reading from EM telemetry system 46A indicating thatthe scale current is exceeding a threshold. For the sake of simplicity,and for the purpose of FIG. 7, detecting that a system, such as atelemetry system 46, has become active or inactive is included as a typeof “sensor reading”.

If receiving the sensor reading causes all of the change conditionsassociated with an inactive configuration profile to be satisfied, thenthe method moves to block 318, where the currently active configurationprofile is changed to be the configuration profile associated with thissatisfied conditions. After changing to the new configuration profile,or if no inactive configuration profile had all of its conditionssatisfied, the method returns to block 312.

If a control signal is transmitted to telemetry system 40, the methodgoes to block 320 to receive the control signal, and then goes todecision block 322. If the received control signal encodes instructionsto add, delete or alter a configuration profile (which may includeadding, deleting or altering the change conditions associated with anygiven configuration profile), method 310 proceeds on to block 324 wherethose additions, deletions or alterations are incorporated by telemetrysystem 40. Such incorporation may be accomplished, for example, bychanging values in a memory, device, structure or service (such as datastorage 204) where configuration profiles and their associated changeconditions are stored.

Method 310 then moves to block 326 where the current state of the systemis re-evaluated so as to determine which configuration profile should beactive. This process may involve, for example, comparing all of the mostrecently measured sensor readings against the current set of changeconditions, together with the current activity or inactivity status ofthe various systems of telemetry system 40, and any other informationused to determine the currently active configuration profile. Method 310then returns to block 312.

If in block 322, the instruction was not one to add, delete or alter aconfiguration profile, then method 310 moves to block 328, wheretelemetry system 40 determines whether the controller signal encodesinstructions to change the currently active configuration profile. If itdoes then method 310 moves on to block 330, where the currently activeconfiguration profile is changed to the one indicated by the controlsignal. Method 310 then moves from block 330, or if the instruction wasnot changed in configuration from block 328, to block 312. If theconfiguration was changed in response to an express instructed change toa particular configuration profile, then the telemetry system 40 may, insome embodiments, not change configuration profiles until expresslyinstructed to do so by a control signal. Telemetry system 40 may also,or alternatively, be configured to continue to assess sensor readingsand control signals and change current configuration profiles inresponse thereto.

FIG. 8 shows schematically how telemetry apparatus 50 may be programmedto change its operating configuration in response to a downlink commandcontaining instructions to execute a particular configuration profile.In the illustrated embodiment a surface operator can send a downlinkcommand by vibration downlink 400, RPM downlink 401, or pressuredownlink 402 in a manner as is known in art. In other embodiments othertypes of downlinks may be used. Flow switch sensor 54 and RPM gyrosensor 56 may receive the vibration downlink 400 or RPM downlink 401commands; the pressure sensor 94 may receive the pressure downlink 402command. Upon receipt of a downlink command analog signal, the CPU ofthe status sensor controller 52 or power controller 90 may decode thereceived signal and extract the bitstream containing the downlinkcommand instructions, in a manner that is known in the art. The statussensor controller 52 or power controller 90 will then read the downlinkcommand instructions and execute the configuration profile portionstored on its memory corresponding to the configuration profilespecified in the downlink command, as well as forward the downlinkcommand instructions to the other controllers 52, 60, 70, 80, 90 viadata bus 98. Upon receipt of the downlink command instructions, the CPUsof the other controllers 52, 60, 70, 80, 90 may also execute theconfiguration profile portions in their respective memories thatcorrespond to the configuration profile specified in the downlinkcommand. In particular:

-   -   the status sensor controller 52 may operate its sensors (e.g.        shock sensor 58, RPM gyro sensor 56, and flow switch sensor 54)        when instructed to do so in the configuration profile (step        403);    -   the EM controller 70 may turn off when the configuration profile        specifies operation in an MP-only mode or alternatively only        transmit survey data in an MP-only mode (step 404), and will        operate the EM telemetry unit 75 according to the instructions        in its configuration profile portion when the configuration        profile portion specifies operation in the EM-only, concurrent        shared, or concurrent confirmation mode (step 405);    -   the interface sensor controller 60 may operate its sensors (e.g.        D&I sensor 62, gamma sensor 64, and D&I backup sensor 66) when        instructed to do so in its configuration profile portion (step        406);    -   the MP controller 80 may turn off when its configuration profile        portion specifies operation in the EM only mode and may operate        the MP telemetry unit 85 when its configuration profile portion        specifies operation in the MP-only, concurrent shared, or        concurrent confirmation mode (step 407); and    -   the power controller 90 may power on or power off the other        controllers 52, 60, 70, and 80 as instructed in its        configuration profile portion, and may otherwise operate to        manage power usage in the telemetry apparatus 50 and shut down        operation when a measured pressure is below a specified safety        threshold (step 408).

FIGS. 9 to 12 schematically illustrate example configuration profilesand the steps performed by each of controllers 52, 60, 70, 80, and 90upon execution of the instructions of their respective portions of theconfiguration profiles stored in their respective memories. In theseexamples, it is assumed that the telemetry apparatus 50 is alreadyoperating according to a configuration that requires both EM and MPtelemetry units to be active, and the sensors (e.g. sensors 54, 56, 58,62, 64, 66, and 94) receive a downlink command (e.g. a vibration, RPM,or pressure downlink command) to execute a new configuration profile.

-   -   In FIG. 9, a first configuration profile is shown which includes        instructions for the telemetry apparatus 50 to operate in an        MP-only mode.    -   In FIG. 10, a second configuration profile is shown which        includes instructions for the telemetry apparatus 50 to operate        in an EM-only mode.    -   In FIG. 11, a third configuration profile is shown which        includes instructions for the telemetry apparatus 50 to operate        in a concurrent confirmation mode.    -   In FIG. 12, a fourth configuration profile is shown which        includes instructions for the telemetry apparatus 50 to operate        in a concurrent shared mode.

Referring to FIG. 9, the status sensor controller 52 decodes a downlinkcommand signal (step 501) to obtain downlink command instructions toexecute the first configuration profile, and forwards these downlinkcommand instructions to the other controllers 60, 70, 80, 90 (step 502).The power controller 90, upon execution of its first configurationprofile portion opens power supply switches to the EM controller 70 andEM telemetry unit 75 to power off these devices (steps 503), and closespower supply switches to the MP controller 80 and MP telemetry unit 85to power on these devices (steps 504) if these switches are not alreadyclosed (in this example they are already closed). The status sensorcontroller 52, upon execution of its first configuration profileportion, reads flow state and RPM state information from its flow switchsensor 54 and RPM gyro sensor 56, respectively (step 505). The interfacesensor controller 60, upon execution of its first configuration profileportion, reads D&I state and gamma state from D&I sensor 62 and gammasensor 64 (step 506). The MP controller 80, upon execution of its firstconfiguration profile portion, reads the measurement data taken bysensors 54, 56, 62, and 64 (steps 507) and sets the timing of thetelemetry transmission based on the flow and RPM measurements, and thenoperates the MP telemetry unit 85 in the manner specified in itsconfiguration profile portion, which includes encoding the measurementdata according to a specified modulation scheme, and having a specifiedmessage frame type, composition, and timing, operating the MP motor tooperate the pulser assembly 152 to generate mud pulse telemetry signals(step 508).

Referring to FIG. 10, the status sensor controller 52 decodes a downlinkcommand signal (step 601) to obtain downlink command instructions toexecute the second configuration profile, and forwards these downlinkcommand instructions to the other controllers 60, 70, 80, 90 (step 602).The power controller 90, upon execution of its second configurationprofile portion, opens power supply switches to the MP controller 80 andMP controller (steps 603) to power off these devices, and closes powersupply switches to the EM controller 70 and EM telemetry unit 75 topower on these devices (steps 604) if these switches are not alreadyclosed (in this example they are already closed). The status sensorcontroller 52, upon execution of its second configuration profileportion, reads flow state and

RPM state information from its flow switch sensor 54 and RPM gyro sensor56, respectively (step 605). The interface sensor controller 60, uponexecution of its second configuration profile portion, reads D&I stateand gamma state from D&I sensor 62 and gamma sensor 64, respectively(step 606). The EM controller 70, upon execution of its secondconfiguration profile portion: reads the measurement data taken bysensors 54, 56 (steps 607) and sensors 62, 64 (step 608); sets thetiming of the telemetry transmission based on the flow and RPMmeasurements (step 609); and operates the EM telemetry unit 75 in themanner specified in its second configuration profile portion (also step609). Operation of EM telemetry unit 75 according to its secondconfiguration profile portion may include: encoding measurement datausing a specified modulation scheme; using a specified message frametype, composition and timing; operating the EM signal generator 72 togenerate a telemetry signal (e.g. an AC telemetry signal); amplifyingthis signal with the EM amplifier 74; and applying the signal across thegap sub 78 via the H-bridge driver 76 (step 609).

Referring to FIG. 11, the status sensor controller 52 decodes a downlinkcommand signal (step 701) to obtain downlink command instructions toexecute the third configuration profile, and forwards these downlinkcommand instructions to the other controllers 60, 70, 80, 90 (step 702).The power controller 90, upon execution of its third configurationprofile portion closes the power switches to both EM controller 70 andEM telemetry unit 75 (steps 703) and MP controller 80 and MP telemetryunit 85 (steps 704) to power on these devices, if these switches are notalready closed (in this example both are already closed). The statussensor controller 52, upon execution of its third configuration profileportion, reads flow state and RPM state information from flow switchsensor 54 and RPM gyro sensor 56, respectively (step 705). The interfacesensor controller 60, upon execution of its third configuration profileportion, reads D&I state and gamma state from D&I sensor 62 and gammasensor 64, respectively (step 706). The MP controller 80, upon executionof its third configuration profile portion, reads the measurement datataken by sensors 54, 56, 62, and 64 (step 707), and sets the timing ofthe telemetry transmission based on the flow and RPM measurements (steps707), and then operates the MP telemetry unit 85 in the manner specifiedin the configuration profile to generate mud pulse telemetry signals(step 708). The EM controller 70, upon execution of its thirdconfiguration profile portion, communicates with the MP controller 80 toobtain the read measurement data (in a “mirrored data” operation) andsets the timing of the telemetry transmission based on the flow and RPMmeasurements (step 709) and operates the EM telemetry unit 75 in themanner specified in the configuration profile to generate EM telemetrysignals (step 710).

The third configuration profile portions for the EM and MP controllers70, 80, may include instructions relating to the type, composition,order and timing of the message frames in both the EM and MP telemetrytransmissions. Referring to FIG. 11A, the third configuration profilemay include, for example, instructions for the interface sensorcontroller 60 to take survey measurements using sensors (e.g. directionand inclination sensor 62, gamma sensor 64, etc.) and for the EMtelemetry unit 75 to transmit a survey message frame containing thesurvey measurements during a “quiet” window while there is no mud flowor drill string rotation. Since mud flow is required for MPtransmissions, the third configuration profile can also includeinstructions for the MP telemetry unit 85 to transmit a survey messageframe while mud is flowing and before the drill string rotates. Sincethe telemetry tool is operating in a concurrent confirmation mode, thethird configuration profile can also contain instructions for the EM andMP telemetry units 75, 85 to each send time-synchronized sliding framescontaining the same data when mud is flowing and the drill string is notrotating. Finally, the third configuration profile can includeinstructions for the EM and MP telemetry units 75, 85 to then sendtime-synchronized rotating frames containing the same data when mud isflowing and the drill string is rotating.

Referring to FIG. 12, the status sensor controller 52 decodes a downlinkcommand signal (step 801) to obtain downlink command instructions toexecute the fourth configuration profile, and forwards these downlinkcommand instructions to the other controllers 60, 70, 80, 90 (step 802).The power controller 90, upon execution of its fourth configurationprofile portion, closes the power switches to both the EM controller 70and EM telemetry unit 75 (steps 803) and the MP controller 80 and MPTelemetry Unit 85 (steps 804) to power on these devices, if theseswitches are not already closed (in this example both are alreadyclosed).

The status sensor controller 52, upon execution of its fourthconfiguration profile portion, reads flow state and RPM stateinformation from flow switch sensor 54 and RPM gyro sensor 56,respectively (step 805). The interface sensor controller 60, uponexecution of its fourth configuration profile portion, reads D&I stateand gamma state from D&I sensor 62 and gamma sensor 64, respectively(step 806). The MP controller 80, upon execution of its fourthconfiguration profile portion, reads the measurement data taken bysensors 54, 56, 62, and 64 (steps 807), sets the timing of the telemetrytransmission based on the flow and RPM measurements, and then operatesthe MP telemetry unit 85 in the manner specified in the configurationprofile to generate mud pulse telemetry signals (step 808). The EMcontroller 70, upon execution of its fourth configuration profileportion, reads the measurement data taken by sensors 54, 56, 62, and 64(steps 809) (in a “independent data acquisition” operation), sets thetiming of the telemetry transmission based on the flow and RPMmeasurements, and operates the EM telemetry unit 75 in the mannerspecified in the configuration profile to generate EM telemetry signals(step 810).

The fourth configuration profile portions for the EM and MP controllers70, 80 may include instructions relating to the type, composition, orderand timing of the message frames in both the EM and MP telemetrytransmissions. Referring to FIG. 12A, the fourth configuration profilemay include, for example, instructions for the interface sensorcontroller 60 to take survey measurements using sensors (e.g. directionand inclination sensor 62, gamma sensor 64, etc.) and for the EMtelemetry unit 75 to transmit a survey message frame containing thesurvey measurements during a “quiet” window while there is no mud flowor drill string rotation.

Since mud flow is required for MP transmissions, the fourthconfiguration profile can also include instructions for the MP telemetryunit 85 to transmit a survey message frame while mud is flowing andbefore the drill string rotates. Since the telemetry tool is operatingin a concurrent shared mode, the fourth configuration profile can alsocontain instructions for each of EM and MP telemetry units 75, 85 toindependently send different data as specified by the configurationprofile. For example, the fourth configuration can contain instructionsfor the EM telemetry unit 75 to transmit gamma, shock and vibrationmeasurements in sliding and rotating frames, and for the MP telemetryunit 85 to transmit toolface measurements in sliding and rotatingframes.

Allocation and Prioritization of Telemetry Data

Apparatus as described herein may include a data control system thatcontrols what data is carried by which telemetry system. The datacontrol system may also control when that data is transmitted (e.g.certain data may be transmitted more frequently than other data, certaindata may be transmitted in real time or near-real-time and other datamay be stored and transmitted later). Where two or more telemetrysystems are provided, the data control system may be operable toselectively: transmit certain data on one telemetry system and no dataon another telemetry system; transmit certain data on one telemetrysystem and other data on the other telemetry system; transmit certaindata on more than one telemetry system; change the selection of data tobe transmitted and/or the allocation of that data among the telemetrysystems and/or how often certain data is transmitted. Where the samedata is transmitted on different telemetry systems it is optionallypossible to transmit updated data more frequently in one telemetrysystem than another.

The ability to allocate data between different telemetry systems can beused to advantage in a wide range of ways. For example, survey data maybe sent by EM telemetry while active drilling is not in progress. Thisrelieves the need to transmit survey data by MP telemetry and permits MPtelemetry to be used to send active data as soon as the flow of drillingfluid is sufficient to support mud pulse telemetry. In an examplemethod, a controller in telemetry system 40, 40A, 50 monitors a sensoroutput to determine whether active drilling is occurring. For example,the controller may monitor the output of a flow sensor. If activedrilling is not occurring (no flow or low flow detected) then thecontroller may cause data, for example survey data, to be transmitted byEM telemetry. If active drilling is occurring (flow exceeds a threshold)then the controller may cause the data to be transmitted by MPtelemetry.

As another example, data that might otherwise be transmitted by EMtelemetry could be transmitted by MP telemetry instead in cases whererotating noise makes EM reception unduly difficult or unreliable orwhere horizontal drilling is being performed and overlying formationsmay impair the effectiveness of EM telemetry. In an example method, datais sent simultaneously by MP telemetry and EM telemetry. The EMtelemetry data may be different from the MP telemetry data. A controllerof a downhole system 40, 40A, 50 determines that EM telemetry isineffective or undesired. The controller may make this determination,for example, based on one or more of: a current of an EM signalgenerator (too high current indicates conductive formations in which EMtelemetry may be ineffective); a downlink signal from the surface usingany available telemetry mode or predefined pattern of manipulation ofdrill string rotation and/or mud flow; an inclinometer reading (thesystem may be configured to not use EM telemetry once the inclination ofthe BHA is closer to horizontal than a threshold angle); and a measureof rotating noise. Upon determining that EM telemetry is ineffective orundesired the controller may automatically shut off the EM telemetrysystem and reallocate data being transmitted to the MP telemetry systemsuch that a desired set of data is transmitted by MP telemetry.

As another example, the ‘duty cycles’ of the different availabletelemetry systems may be varied. Each telemetry system may be active atsome times and off at other times. For example, where there is a need totransmit certain data that exceeds the available bandwidth of apreferred telemetry system, another telemetry system may be made activeonly for selected periods which are sufficient to carry the balance ofthe data to be transmitted. As another example, each telemetry systemmay be configured to actively transmit data in certain time slots and tobe off in other time slots. This may be done independently for eachtelemetry system. The pattern of when a telemetry system will be on oroff may be specified in a configuration profile. In another embodiment atelemetry system may operate on demand. When that telemetry system hasdata to transmit then the telemetry system may be made active for longenough to transmit the data. Otherwise the telemetry system may be keptin a non-transmitting state.

The data control system may comprise a switchboard that matchesavailable data to available slots in a data transmission protocol orprotocols. For example, in some embodiments, a telemetry systemtransmits data in frames which can each carry a certain amount of data.In such embodiments the data control system may match data to betransmitted to slots in data frames to be transmitted. With anarchitecture in which all sensor systems are interconnected by a datatransmission bus (FIG. 3 is but one example of such an architecture) thedata control system can transmit any selected data on any availabletelemetry system.

Various data transmission protocols may be used so that surfaceequipment will understand the significance of the transmitted data. Forexample:

-   -   the data control system may transmit control information        indicating what data will be, is being or has been transmitted        in available slots of a data transmission protocol.    -   the data control system may assign data to slots in a data        transmission protocol according to instructions provided from        the surface.    -   the data control system may be configured to assign data to        slots in a data transmission protocol according to one or more        predetermined arrangements.    -   the data may be distinguishable (e.g. outputs from certain        different sensors may typically have values in ranges different        from the outputs of other sensors) such that the assignment of        data to slots in a data transmission protocol may be inferred        from analysis of data received at the surface.    -   the data control system may assign data to slots in a data        transmission protocol according to predetermined rules such that        surface equipment can infer from the predetermined rules what        data the data control system has assigned to different slots in        a data transmission protocol.    -   the data control system may be configured to use different data        transmission protocols for different arrangements of transmitted        data such that surface equipment may infer the arrangement of        transmitted data by determining what transmission protocol the        data control system is using.

Other possibilities also exist. These methods may also be combined inany combinations to yield further methods. In some embodimentsinformation regarding the arrangement of data being transmitted usingone telemetry system is transmitted by another telemetry system.

A protocol may specify other aspects of transmitted signals such as acoding type to be used (e.g. 8 PSK, QPSK, FSK, etc.) and bit rate.

Data Frames

In some example embodiments data is transmitted according to a protocolwhich specifies syntax for frames of one or more different types. Eachframe may contain a group of data elements. Configuration informationmay assign different data to different frames. For example, onetelemetry system may transmit the most recent measurements fromdirection and inclination sensor 62 in some frames and may transmitmeasurements from one or more of the remaining sensors in other frames.The frames may alternate such that frames carrying one selection of dataare interleaved with frames carrying other selections of data.

Each frame may comprise a header section that establishes the timing,amplitude and type of message frame. For example, the header maycomprise two parts that are transmitted as one continuous stream. Thefirst part may comprise a specified fixed waveform. The waveform of thefirst part may have a pattern selected such that the pattern can berecognized by the surface processing equipment and is easilydistinguished from noise. Transmission of this pattern may serve tosynchronize the receiver to the timing and amplitude of the waveform.The second part of the header may comprise a variable waveform thatfunctions to identify a type (ID) of the frame. The header section mayinclude an identifier that enables a recipient of the frame to readand/or make sense of the data portion. The general composition of suchmessage frames is known in the art and thus specific details are notdiscussed in further detail here.

Different frame types may be called for depending on the functions beingcarried out by the drill rig. For example:

-   -   Survey frames which include data that is typically high priority        (e.g. inclination, azimuth, sensor qualification/verification        data, plus other information as desired) may be sent in        preparation for drilling. For example, survey frames may be sent        by EM telemetry during a drill pipe connection or by MP        telemetry as soon as sufficient mud is flowing.    -   Sliding frames may be sent during drilling when the drill string        is not being rotated from the surface. Sliding frames may, for        example be configured to send a steady stream of toolface        readings and may also include additional data sent between        successive toolface messages. In an example embodiment sliding        frames may be defined by the data control system to consist of        alternating toolface readings and gamma readings in the data        portion of each frame. The header portion of a sliding frame may        include a unique identifier, not shared by other types of        frames, so that a recipient who receives the header portion of a        sliding frame will know that the data portion that follows will        conform to a known structure associated with that identifier.    -   Rotating frames may be sent while the drill string is rotating        at the surface. Rotating frames typically do not include        toolface data as such data is not generally relevant while the        drill string is being rotated from the surface. Any other data        may be included in rotating frames as desired.    -   Status frames may be sent at any time to alert surface equipment        to the current status of a downhole system. Status frames may be        sent, for example to signal a change or event, such as a change        in the type(s) of telemetry being used, a significant change in        sensor readings, a change in telemetry speed, or the like.        Status frames may be generated to alert the receiver of changes        in the telemetry type, speed, amplitude, configuration change,        significant sensor change (such as a non-functioning or        reduced-functioning accelerometer, for example), or other change        to the status of the downhole tool. The sending of status frames        may be triggered by particular events. For example, a downlink        command received from the surface, a timer which calls for        status frames to be transmitted at certain times, a        configuration which calls for status frames to be transmitted at        certain stages of drilling, or a sensor failure in the tool, or        the like. A status frame may include an identifier which        identifies which configuration profile is currently active on        the downhole system and is being used to transmit the telemetry        signals; this identifier will allow the surface transceiver 26        to select the correct demodulation and other decoding operations        to decode the received signals at surface.    -   Other frame types may optionally be generated in other contexts.

The particular structure of the data portion of any type of frame mayvary by embodiment or configuration of the data control system.

A downhole tool may be configured to switch automatically betweentransmitting different types of frames. For example, the downhole toolmay comprise a flow sensor (which may monitor flow by detectingvibration of the tool). The tool may control when survey data isacquired and when the tool sends survey frames based on an output of theflow sensor. The tool may configure itself to send survey frames whenthe flow sensor detects no flow and may configure itself to send activeframes (e.g. sliding frames or rotating frames) when the flow sensordetects flow in excess of a threshold flow. The tool may comprise anaccelerometer or other rotation sensor and may automatically switchbetween transmitting sliding frames and rotating frames based on adetected rotation rate (with rotating frames being transmitted when therotation rate exceeds a threshold). In some embodiments, a status sensorcontroller (e.g. status sensor controller 52) monitors sensor readingsto determine a current drilling mode and triggers switchingconfigurations to use different types of data frames when changes in thedrilling mode are detected.

In some embodiments, configuration profiles stored in one or moredownhole memories specify data content for a plurality of differentpredetermined frames. Each frame may specify a different set of data tosend to the surface. An example of such an embodiment is illustrated byFIG. 6A. Telemetry controller 202 is configured to decide which frame(s)to send to the surface. This decision may be based upon downholeconditions picked up by sensors and/or downlink commands from thesurface.

Different frames may specify different combinations of information(parameters) to be transmitted to the surface. For example, Frame ‘1’may include only data from a direction and inclination (D&I) system.Frame ‘2’ may include a combination of data from the D&I system and datafrom a gamma system. Frame ‘3’ may include a combination of data fromthe D&I system, data from one or more pressure sensors and othersensors' data etc. Any suitable number of predefined frames may beprovided. The downhole system may be highly configurable so that anoperator may set up the downhole system to provide frames that includeany combination of data that may be expected to be useful for a proposeddrilling operation.

Data Control Systems

A data control system may be implemented by one or more suitablyconfigured controllers (e.g. controller 42 of FIG. 2 or one or more ofcontrollers 42A, 42B of FIG. 2A or one or more of the controllers ofapparatus 50). A data control system may be distributed. For example, aseparate data control system may be provided for each telemetry system.These data control systems may operate independently of one another.Each of the data control systems may be configured to transmit certainitems. The configurations of different data control systems may becomplementary so that each necessary item of data is transmitted overone or more of the telemetry systems. In such embodiments it is possiblebut not mandatory for the data control systems to interact with oneanother in normal operation.

In other embodiments the data control system is centralized andallocates data to available transmission slots for two or more telemetrysystems. In still other embodiments each telemetry system includes aquasi-independent data control system but one of the data controlsystems acts to coordinate operation of other data control systems. Inother embodiments, the data control system includes a central part thatcoordinates operation of subsystems associated with the differenttelemetry systems.

FIG. 6 shows schematically an example telemetry configuration system 200that includes a telemetry controller 202. Telemetry controller 202 maybe, for example implemented by software code executing on EM controller70 or MP controller 80. Telemetry controller 202 may more generally beany controller of control system 42 that is connected to a data bus thatpermits it to access data that could be transmitted and telemetrysystems available to transmit the data.

Telemetry controller 202 has access to data storage 204. Data storage204 may be a memory accessible by telemetry controller 202, a set ofregisters housed within telemetry controller 202 (if telemetrycontroller 202 comprises a CPU or other register-containing device), orany other suitably-configured device, system or service capable forstoring information accessible to a telemetry controller 202.

Data storage 204 includes one or more data locations 206. For example,data storage 204 includes data locations 206A, 206B and 206C. Each datalocation 206 may store or identify (e.g. by way of an address orpointer) an item of data that may be transmitted by a telemetry system.In the example shown in FIG. 6, data location 206A corresponds to datafrom direction and inclination sensor 62, data location 206B correspondsto data from gamma sensor 64, and data location 206C corresponds to datafrom pressure sensor 94. Data locations 206 collectively provide datathat is available to be included in data to be transmitted to surfacetransceiver 26 by a telemetry system.

Data storage 204 includes one or more data locations 207. For example,data storage 204 includes data locations 207A, 207B, 207C and 207D. Eachdata location 207 may correspond to an available slot in which an itemof data may be transmitted by a telemetry system. Each data location 207may include a value that identifies one of data locations 206. Thus, thesequence of items of data to be transmitted by a telemetry system may becontrolled by writing values to data locations 206 which identify datato be transmitted and values to data locations 207 which identify thesequence in which that data will be transmitted by a telemetry system.In some embodiments, different sets of data locations 207 may beprovided for different telemetry systems.

Those of skill in the art will understand that a similar result may beachieved using a single set of data locations for each telemetry systemin which the single set of data locations each corresponds to anavailable transmission slot and each can contain or identify an item ofdata to be transmitted.

Telemetry controller 202 maps data locations 206 to the contents of dataframes for transmission. For example, telemetry controller 202 may beconfigured to transmit the data identified by data location 206A and206B in one frame, and to transmit data identified by data locations206C, 206D and 206E (data locations 206D and 206E not depicted) in thenext frame. On subsequent frames, telemetry controller 202 may advanceto yet further data locations 206F (not depicted) and so on or, if nofurther data locations are available, may loop back to data locations206A and 206B.

As another example, telemetry controller 202 may be configured totransmit the data identified by one or more data locations 206 (such as206A) in each frame, and to vary which of the data associated with theremaining data locations 206 are included in each of the subsequentframes.

For example, if a telemetry controller 202 is configured such that eachframe includes the data identified by the next three data locations 206in sequence, every third data location 206 might be encoded with dataoriginating from a highly important sensor, such as direction andinclination sensor 62, thereby ensuring that direction and inclinationinformation is transmitted in every frame, while still leaving room foradditional sensor information to be cycled through in subsequent frames.A similar result may be achieved by encoding only one data location 206(suppose data location 206A) in a given data storage 204 with dataidentifying direction and inclination sensor 62 and configuringtelemetry controller 202 to include the data identified by data location206A in every frame.

Although it is possible for telemetry systems to operate independently,or for a downhole system to transmit data using fewer than all availabletelemetry systems 46 (e.g. in “EM-only” or “MP-only” modes), in at leastsome embodiments telemetry systems operate cooperatively to transmitdata. Any one or more controllers may be configured to transmitinformation on one or more telemetry systems. Which data is transmittedvia which telemetry systems may be determined in response to the currentconfiguration of the downhole system (for example as specified by aconfiguration profile) and, in some embodiments, a telemetryconfiguration system such as example telemetry configuration system 200.

Conditional Transmission of Selected Data

In some embodiments, telemetry controller 202 or, more generally,control system 42 may be configured to monitor certain parameters and todetermine whether or not to transmit values for the monitored parametersto the surface by telemetry based on changes in the parameter values.Changes may be measured over a time frame (e.g. how much has theparameter value changed in the past 10 seconds or the past minute or thepast 10 minutes or the past hour) and/or in relation to themost-recently transmitted value for the same parameter.

For example, in one example embodiment control system 42 records valuesof a number of parameters as previously transmitted to the surface bytelemetry. Control system 42 then compares a current value of aparameter to the previously-transmitted value for the parameter. If thiscomparison indicates that the value for the parameter has changed bymore than a threshold amount then the controller may be configured totransmit the current value for the parameter to the surface. If thecomparison indicates otherwise then controller 42 may skip transmittingthe current value for the parameter. The comparisons may be made in anysuitable way (e.g. subtracting one of the current andpreviously-transmitted parameter values from the other, determining aratio of the current and previously-transmitted parameter values etc.).Different change thresholds may be provided for different parameters.

In addition or in the alternative control system 42 may record values ofthe parameters at intervals (which may optionally be different fordifferent parameters) and may compare a currently-recorded value for aparameter to a previous value (or an average or weighted average of anumber of previous values) and determine whether the change exceeds athreshold. Again, different thresholds may be provided for differentparameters.

Comparisons as described above may be made periodically, and/or eachtime a new value for a parameter is obtained and/or each time there isan opportunity for transmission of such parameter values.

In some embodiments control system 42 may prioritize transmission ofcurrent parameter values which are different enough from previous values(for example according to differences as determined above) to requireretransmission. Parameter values that are not different enough fromprevious values do not need to be transmitted. One advantage oftransmitting certain parameter values only if the values have changed isthat the amount of power required for data transmission may be reducedand battery life may therefore be extended. Another advantage that maybe achieved in some embodiments is freeing bandwidth to transmit otherdata.

Prioritizing of such transmissions may be based upon one or both of apredetermined priority order and an amount of change of the parameter.In an example embodiment, control system 42 maintains an ordered list ofthe monitored parameters. Control system 42 determines as above whetherit is desirable to transmit a current value for any of the parameters.When an opportunity arrives to transmit values for one or more of theparameters controller 42 may proceed down the ordered list and transmitthe highest-priority ones of the parameters for which control system 42has determined that the current value of the parameter should betransmitted. Where the opportunity exists to transmit N currentparameter values where N is some integer then control system 42 may sendthe N highest-priority ones of the parameters for which control system42 has determined that the current value of the parameter should betransmitted. Control system 42 may additionally transmit in a header orother information identifying the specific parameter values beingtransmitted.

As a specific example, a control system 42 may be configured to transmitdata in sets (e.g. frames) on one or more telemetry systems. Some framesmay be reserved for specific data. For example, the first frame andevery third frame after that may carry a first type of information (e.g.direction and inclination information). The second frame and every thirdframe after that may carry a second type of information (e.g. gammainformation). The third frame and every third frame after that may beconfigured to carry variable information (i.e. one or more currentvalues for parameters which have been selected for transmission based ona change in their values).

As another example, a control system 42 may be configured to send datain frames in which a portion of some or all frames is allocated to carrycurrent values for selected parameters that have changed enough torequire retransmission (if any). Where a selected parameter has changedby less than a threshold amount since a last time a value for theselected parameter was transmitted transmission of the value of theselected parameter may be suppressed.

As another example, control system 42 may be configured to send data fora plurality of parameters in a sequence. Control system 42 may check todetermine whether it is unnecessary to transmit some or all of theparameters (e.g. it may be unnecessary to transmit a current parametervalue if the current parameter value is close to thepreviously-transmitted parameter value).

Where controller 42 determines that transmitting current values for oneor more other parameters is unnecessary then controller 42 may beconfigured to perform one or more of:

-   -   leaving a gap where the parameter value would have been        transmitted;    -   transmitting one or more special symbols in the slot where the        parameter value would have been transmitted (the symbols may        optionally be selected for low power consumption and/or low        latency); or    -   compressing the remaining data together (and, if necessary or        desired, transmitting information identifying the data        transmitted and/or not transmitted).

In some embodiments control system 42 monitors two or more differentsets of parameters (the sets of parameters could optionally have some orall members in common). Each telemetry system of a plurality oftelemetry systems may be associated with one of the sets of parametersand configured to transmit current values for parameters from thecorresponding set of parameters that have changed enough to requireretransmission (if any).

In some embodiments each telemetry system comprises a separatecontroller and the controller is configured to monitor parameters in thecorresponding set and to transmit current values of the parameters wherea condition relating to a change in the parameter value is satisfied.For example, an EM telemetry system may include a controller configuredto monitor parameters such as inclination, shock and stick-slip and maytransmit current values for one or more of these parameters in responseto determining that the current value(s) of the one or more parametershas changed by more than a threshold amount relative to a previousvalue(s) for the one or more parameters. In the same apparatus an MPtelemetry system may include a controller configured to monitor valuesfor a different set of parameters such as battery voltage (or state ofcharge), azimuth and temperature.

In some embodiments, a control system implements a method whichcomprises periodically transmitting certain data on a telemetry systemand conditionally transmitting other data (‘conditional data’) on thetelemetry system. The condition may relate to a difference between acurrent value for the conditional data and a previous value for theconditional data and/or a comparison of the conditional data to athreshold (e.g. certain data may be transmitted if its value is lowerthan a threshold, other data may be transmitted if its value exceeds athreshold).

In another embodiment, system 42 may apply an algorithm that usespreviously-transmitted data (e.g. previously-transmitted values for theparameter) to predict a current value of a parameter. System 42 maytransmit the current value of the parameter if it differs from the valuepredicted by the predictive algorithm by more than a threshold amount.System 42 may suppress transmission of the current value of theparameter if the predictive algorithm is doing a good job of estimatingthe current parameter value (e.g. the value predicted by the predictivealgorithm differs from the current parameter value by less than athreshold amount). In some embodiments the predictive algorithmcomprises fitting a function to two or more previously-transmittedvalues of the parameter. The function may, for example, comprise alinear function, a second-or higher-degree polynomial function, a splinefunction, etc. Where system 42 does not transmit the current value ofthe parameter, surface equipment may use the predictive algorithm andpreviously-transmitted parameter values to estimate the current value ofthe parameter.

As another example, a telemetry system may be configured to transmit acertain set of data. The telemetry system may monitor priority levels ofone or more sensors. The priority levels may be determined, for example,according to one or more of: a length of time since data from the sensorwas last transmitted; a rate of change of the data from the sensor; apattern of data from one or more sensors satisfying a rule; a cumulativechange since data from the sensor was last transmitted; a predeterminedpriority level associated with the sensor (such that, for example, newdata from the sensor is automatically assigned a high priority); and/orthe like. In response to determining that data from one or more sensorshas a priority higher than a threshold level the telemetry system mayautomatically insert data from the high-priority sensor(s) into aspecial frame or a special location in an existing frame.

A telemetry system that includes plural telemetry transmitters mayoptionally be configured to deliver diagnostic information regarding onetelemetry transmitter (and any associated systems) by way of anothertelemetry transmitter. The diagnostic information may, for example,comprise information such as: status information for various subsystems;measured values such as power voltage and/or current, diagnosticreadings from applicable circuits or circuit boards; and the like. Suchinformation may be transmitted while the telemetry system is stilldownhole and used by surface personnel to diagnose and prepare to repairthe other telemetry system, if necessary.

A signal receiver at the surface may be configured to keep track of wheneach received parameter value was last updated. The signal receiver mayoptionally detect gaps in telemetry data where a parameter value isomitted (e.g. because control system 42 has determined that the currentvalue of a parameter is close to—differs by less than a threshold amountfrom—a most-recently transmitted value for the parameter) and/or othertelemetry signals indicating that the current parameter value is notbeing transmitted. The signal receiver may display parameters in amanner that indicates how recently displayed values for differentparameters were received (e.g. by displaying parameter values in certaincolors and/or fonts and/or displaying indicia associated with theparameter values).

Where a surface system detects that current values for one or moreparameters have not been included in a received transmission then thesurface system may optionally display an indicia which indicates thatthe displayed value was not received in the most-recently-transmittedset of parameter values. For example, the surface system may display asymbol, display the parameter value in a particular font, color, fontattribute (e.g. flashing) or the like. As another example, the surfacesystem may annotate a displayed value for the parameter with a toleranceamount. For example, suppose that a parameter has a current value of18.0 degrees, a previously-transmitted value of the same parameter was17.5 degrees and a threshold for change of the parameter is 0.9 degrees.Since the current value for the parameter differs from thepreviously-transmitted value of the parameter by 0.5 degrees, which isless than the threshold of 0.9 degrees, then control system 42 may omitsending the current parameter value. The surface system may have accessto the threshold (in this example 0.9 degrees) and, knowing that theparameter has been omitted, may display 17.5±0.9 degrees as the valuefor the parameter. Suppose that the value for the parameter subsequentlychanges to 18.5 degrees. Now the difference between the current value ofthe parameter and the most-recently transmitted value of the parameterexceeds the threshold (since 18.5-17.5>0.9). Therefore control system 42may transmit the current value of the parameter and the surface systemmay display the current value of the parameter (without necessarilydisplaying a tolerance range or otherwise indicating that the displayedvalue was not received in the most-recently-transmitted set of parametervalues).

Other examples in which data may be transmitted conditionally includecases where it may be difficult or costly in terms of battery life totransmit certain data. For example, in very deep work, a system asdescribed herein could be configured to send EM survey data in periodsbetween active drilling only in cases where noise during active drillingmay be too high for reception while drilling. This saves battery lifeand allows for faster surveys.

Receiving Telemetry Data

A significant feature of some embodiments is a single surface system forreceiving and decoding telemetry that has been transmitted by aplurality of distinct telemetry subsystems of a downhole system.Providing such a single system permits data to be split among two ormore different telemetry subsystems at the downhole system and thenrecombined at the surface equipment in a way that is seamless to users.All information transmitted by telemetry from the downhole system may bepresented on a single display or set of displays in a consistent manner.Further, as described elsewhere herein, with such a system, telemetryinformation provided by way of one telemetry subsystem (e.g. an EMtelemetry subsystem) may be used to support telemetry provided by way ofanother telemetry subsystem (e.g. an MP telemetry subsystem). Thissupport may include transmitting configuration information indicating away in which data is being encoded on the other telemetry subsystem,transmitting overflow data, carrying the data of a malfunctioningtelemetry system or the like.

Referring to FIG. 13, the surface transceiver 26 detects and processesthe EM and MP telemetry signals transmitted by the telemetry apparatus50, and sends these signals to computer 32 which decodes these signalsto recover the telemetry channels and to convert measurement data foruse by the operator. Computer 32 includes executable program codecontaining demodulation technique(s) corresponding to the selectedmodulation technique(s) used by the EM and MP telemetry units 75, 85which are used to decode the modulated telemetry signals. The computer32 also contains the same set of configuration profiles that weredownloaded onto the telemetry apparatus 50, and may refer to thespecific configuration profile used by the telemetry apparatus 50 todecode the received telemetry signals that were transmitted according tothat configuration profile.

Surface transceiver 26 may include an MP receiver and filters, an EMreceiver and filters, a central processing unit (receiver CPU), and ananalog to digital converter (ADC). More particularly, surfacetransceiver 26 may comprise a surface receiver circuit board containingthe MP and EM receivers and filters. The EM receiver and filter maycomprise a preamplifier electrically coupled to the communication cables27 to receive and amplify the EM telemetry transmission comprising theEM carrier wave, and a band pass filter communicative with thepreamplifier configured to filter out unwanted noise in thetransmission. The ADC may also be located on the circuit board and mayoperate to convert the analog electrical signals received from the EMand MP receivers and filters into digital data streams. The receiver CPUmay contain a digital signal processor (DSP) which applies variousdigital signal processing operations on the data streams by executing adigital signal processing program stored on its memory. Alternatively,separate hardware components can be used to perform one or more of theDSP functions; for example, an application-specific integrated circuit(ASIC) or field-programmable gate arrays (FPGA) can be used to performthe digital signal processing in a manner as is known in the art. Suchpreamplifiers, band pass filters, and A/D converters are well known inthe art and thus are not described in detail here. For example, thepreamplifier can be an INA118 model from Texas Instruments, the ADC canbe an ADS1282 model from Texas Instruments, and the band pass filter canbe an optical band pass filter or an RLC circuit configured to passfrequencies between 0.1 Hz to 20 Hz.

Computer 32 may be communicative with the surface transceiver 26 via anEthernet or other suitable communications cable to receive the processedEM and MP telemetry signals and with the surface operator to receive theidentity of the configuration profile the telemetry apparatus 50 isusing to transmit the telemetry signals (“operating configurationprofile”). Computer 32 in one embodiment is a general purpose computercomprising a central processing unit (CPU and herein referred to as“surface processor”) and a memory having program code executable by thesurface processor to perform various decoding functions includingdigital signal-to-telemetry data demodulation. The computer 32 may alsoinclude program code to perform digital signal filtering and digitalsignal processing in addition to or instead of the digital signalfiltering and processing performed by the surface transceiver 26.

The surface processor program code may utilize demodulation techniquesthat correspond to the modulation techniques used by the telemetryapparatus 50 to encode the measurement data into the EM and MP telemetrysignal. These modulation techniques are applied to the EM and MPtelemetry signals received by the surface transceiver 26 to recover themeasurement data.

Alternatively, or additionally, the surface transceiver 26 and/orcomputer 32 may be programmed to retrieve the identity of the operatingconfiguration profile used by the telemetry apparatus 50 from thetelemetry signals themselves. The identity of the operatingconfiguration profile may be located in the status frame, or anothermessage frame. The operating configuration profile identity can also berepeated in the telemetry signal, e.g. at the end of a survey frame.

In some embodiments, surface equipment may be connected to sensors fromwhich a current drilling mode can be inferred. For example, a surfacesensor may determine whether drilling fluid is flowing or not in thewellbore. In some embodiments data from an MP transducer at the surfaceis processed to determine whether or not fluid is flowing in thewellbore.

A downhole system as described herein may be configured to send certaininformation at times that are synchronized to changes in a drillingmode. For example, a downhole system may be configured to cause an EMsubsystem to send a long header (specifying a way in which data will betransmitted by EM and/or MP telemetry) at a specified time after aflow-off condition starts. The surface equipment may, for example,detect the onset of the flow-off condition by monitoring an output of apressure transducer at the surface (which may also serve as a detectorfor MP telemetry pulses at the surface). The surface equipment may thenprocess EM telemetry data to look for a long header at the applicabletime.

Alternatively, or in the event that the surface transceiver 26 and/orcomputer 32 cannot retrieve the identity of the operating configurationprofile from the telemetry signal, or does not receive the identity ofthe operating configuration profile from the operator, or there is amismatch between the identities detected in the telemetry signal andprovided by the operator, the surface transceiver 26 and/or computer 32can be programmed to attempt to decode the received telemetrytransmission in all known telemetry modes and using all knowndemodulation techniques until the correct telemetry mode anddemodulation technique is found.

Computer 32 may further contain program code executable by its processorto process telemetry signals transmitted by the telemetry apparatus 50in the concurrent shared or confirmation modes. More particularly, whenthe transmission was made in the concurrent shared mode, program codemay be executed which combines the measurement data from the MP and EMdata channels into a single data stream for display to the operator.When the transmission was made in the concurrent confirmation mode,program code may be executed which compares the received EM and MPtelemetry signals and selects the telemetry signal providing the highestconfidence value to decode and obtain the measurement data.

Certain embodiments described herein offer the advantage of multipledifferent telemetry types and the flexibility to use different telemetrysystems in different ways (examples of which are described above) in asystem in which power is supplied by a common set of batteries and datais acquired by a common set of sensors accessible to each of thetelemetry systems. While a downhole tool according to some embodimentsmay have the capability to make autonomous decisions regarding datatelemetry this is not necessary in all embodiments.

An advantage of some embodiments is great flexibility in that a downholetool may be configured to perform according to the preferences of adrill rig operator. The downhole tool may be configured to use aselected single telemetry system (with all others inhibited) if thatmeets the operator's requirements. In other cases the downhole tool maybe configured in any of the ways described above to use two or moretelemetry systems, thereby providing more data of a given type, data ofmore different types, and/or data having higher reliability.

While a number of exemplary aspects and embodiments have been discussedabove, those of skill in the art will recognize certain modifications,permutations, additions and sub-combinations thereof. All suchmodifications, permutations, additions and sub-combinations are includedin the invention described herein.

Interpretation of Terms

Unless the context clearly requires otherwise, throughout thedescription and the

-   -   “comprise”, “comprising”, and the like are to be construed in an        inclusive sense, as opposed to an exclusive or exhaustive sense;        that is to say, in the sense of “including, but not limited to”.    -   “connected”, “coupled”, or any variant thereof, means any        connection or coupling, either direct or indirect, between two        or more elements; the coupling or connection between the        elements can be physical, logical, or a combination thereof.    -   “herein”, “above”, “below”, and words of similar import, when        used to describe this specification shall refer to this        specification as a whole and not to any particular portions of        this specification.    -   “or”, in reference to a list of two or more items, covers all of        the following interpretations of the word: any of the items in        the list, all of the items in the list, and any combination of        the items in the list.    -   the singular forms “a”, “an”, and “the” also include the meaning        of any appropriate plural forms.

Words that indicate directions such as “vertical”, “transverse”,“horizontal”, “upward”, “downward”, “forward”, “backward”, “inward”,“outward”, “vertical”, “transverse”, “left”, “right”, “front”, “back”,“top”, “bottom”, “below”, “above”, “under”, and the like, used in thisdescription and any accompanying claims (where present) depend on thespecific orientation of the apparatus described and illustrated. Thesubject matter described herein may assume various alternativeorientations. Accordingly, these directional terms are not strictlydefined and should not be interpreted narrowly.

Headings are included for convenience only and are not to be used tointerpret the meaning of the disclosure or claims.

Where a component (e.g. a circuit, system, assembly, device, drillstring component, drill rig system, etc.) is referred to above, unlessotherwise indicated, reference to that component (including a referenceto a “means”) should be interpreted as including as equivalents of thatcomponent any component which performs the function of the describedcomponent (i.e., that is functionally equivalent), including componentswhich are not structurally equivalent to the disclosed structure whichperforms the function in the illustrated exemplary embodiments of theinvention.

All headings in this document are for convenience of the reader only.Text under any heading may also relate to other headings. The wording ofthe headings themselves does not limit in any way the meaning of anytext.

Specific examples of systems, methods and apparatus have been describedherein for purposes of illustration. These are only examples. Thetechnology provided herein can be applied to systems other than theexample systems described above. Many alterations, modifications,additions, omissions and permutations are possible within the practiceof this invention. This invention includes variations on describedembodiments that would be apparent to the skilled addressee, includingvariations obtained by: replacing features, elements and/or acts withequivalent features, elements and/or acts; mixing and matching offeatures, elements and/or acts from different embodiments; combiningfeatures, elements and/or acts from embodiments as described herein withfeatures, elements and/or acts of other technology; and/or omittingcombining features, elements and/or acts from described embodiments.

It is therefore intended that the following appended claims and claimshereafter introduced are interpreted to include all such modifications,permutations, additions, omissions and sub-combinations as mayreasonably be inferred. The scope of the claims should not be limited bythe preferred embodiments set forth in the examples, but should be giventhe broadest interpretation consistent with the description as a whole.

What is claimed is:
 1. A drilling method comprising: advancing a drillstring while pumping drilling fluid through a bore of the drill stringduring active drilling periods separated by flow-off periods duringwhich a flow of the drilling fluid through the drill string isdiscontinued; and communicating telemetry data from a downhole system tosurface equipment; wherein the drilling method comprises, establishing adata communication protocol having slots for a plurality of specificdata items and, at the downhole system, obtaining a specific one of theplurality of specific data items by obtaining a current reading from asensor, the current reading corresponding to a current value for adownhole parameter measured by the sensor, comparing the current valueof the downhole parameter with one or more previously-transmitted valuesfor the downhole parameter, the one or more previously-transmittedvalues comprising one or more previously obtained readings from thesensor; and, not transmitting the current value of the downholeparameter if the comparison indicates that the current value of thedownhole parameter is within a threshold amount of a most-recentlypreviously-transmitted value for the downhole parameter; andtransmitting the current value of the downhole parameter if thecomparison indicates that the current value of the downhole parameter isnot within the threshold amount of the most-recentlypreviously-transmitted value for the downhole parameter.
 2. A methodaccording to claim 1 wherein said comparing the current value of thedownhole parameter with the one or more previously-transmitted valuesfor the downhole parameter comprises, at the downhole system, computinga predicted value for the current value of the downhole parameter basedon a plurality of the one or more previously-transmitted values for thedownhole parameter and comparing the current value for the downholeparameter to the predicted value for the current value of the downholeparameter.
 3. A method according to claim 1 further-comprising, at thesurface equipment, detecting an absence of the current value for thedownhole parameter transmitted from the downhole system and displayingone of the one or more previously-transmitted values for the downholeparameter.
 4. A method according to claim 3 further comprising, at thesurface equipment, displaying an indicia indicative that the displayedone of the one or more previously-transmitted values for the downholeparameter is not the current value for the downhole parameter.
 5. Amethod according to claim 1 wherein the plurality of specific data itemscorrespond to a plurality of parameters chosen from a group consistingof inclination, shock, stick-slip, battery voltage, state of charge,azimuth, temperature, speed of rotation of the drill string, directionof rotation of the drill string and gamma emission.